Document and Entity Information - USD ($) $ in Billions	12 Months Ended
Document and Entity Information - USD ($) $ in Billions	Dec. 31, 2015	Jan. 29, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Trading Symbol	ED
Entity Registrant Name	CONSOLIDATED EDISON INC
Entity Central Index Key	0001047862
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		293,589,401
Entity Public Float			$ 17.0
CECONY
Document Information [Line Items]
Entity Registrant Name	CONSOLIDATED EDISON CO OF NEW YORK INC
Entity Central Index Key	0000023632
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer

Consolidated Income Statement - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUES
Electric	$ 8,832	$ 9,114	$ 8,756
Gas	1,709	1,933	1,821
Steam	629	628	683
Non-utility	1,384	1,244	1,094
TOTAL OPERATING REVENUES	12,554	12,919	12,354
OPERATING EXPENSES
Purchased power	2,973	3,417	3,099
Fuel	248	285	320
Gas purchased for resale	495	811	635
Other operations and maintenance	3,344	3,294	3,137
Depreciation and amortization	1,130	1,071	1,024
Taxes, other than income taxes	1,937	1,877	1,895
TOTAL OPERATING EXPENSES	10,127	10,755	10,110
Gain on sale of solar electric production projects	0	45	0
OPERATING INCOME	2,427	2,209	2,244
OTHER INCOME (DEDUCTIONS)
Investment and other income	35	54	24
Allowance for equity funds used during construction	5	2	4
Other deductions	(16)	(14)	(15)
TOTAL OTHER INCOME	24	42	13
INCOME BEFORE INTEREST AND INCOME TAX EXPENSE	2,451	2,251	2,257
INTEREST EXPENSE
Interest on long-term debt	632	587	578
Other interest	24	5	143
Allowance for borrowed funds used during construction	(3)	(1)	(2)
NET INTEREST EXPENSE	653	591	719
INCOME BEFORE INCOME TAX EXPENSE	1,798	1,660	1,538
INCOME TAX EXPENSE	605	568	476
NET INCOME	$ 1,193	$ 1,092	$ 1,062
Net income per common share — basic (dollars per share)	$ 4.07	$ 3.73	$ 3.62
Net income per common share — diluted (dollars per share)	4.05	3.71	3.61
DIVIDENDS DECLARED PER COMMON SHARE (dollars per share)	$ 2.60	$ 2.52	$ 2.46
AVERAGE NUMBER OF SHARES OUTSTANDING — BASIC (IN MILLIONS) (shares)	293.0	292.9	292.9
AVERAGE NUMBER OF SHARES OUTSTANDING — DILUTED (IN MILLIONS) (shares)	294.4	294.0	294.4
CECONY
OPERATING REVENUES
Electric	$ 8,172	$ 8,437	$ 8,131
Gas	1,527	1,721	1,616
Steam	629	628	683
TOTAL OPERATING REVENUES	10,328	10,786	10,430
OPERATING EXPENSES
Purchased power	1,719	2,091	2,021
Fuel	248	285	320
Gas purchased for resale	337	609	532
Other operations and maintenance	2,881	2,873	2,735
Depreciation and amortization	1,040	991	946
Taxes, other than income taxes	1,856	1,798	1,816
TOTAL OPERATING EXPENSES	8,081	8,647	8,370
OPERATING INCOME	2,247	2,139	2,060
OTHER INCOME (DEDUCTIONS)
Investment and other income	5	22	11
Allowance for equity funds used during construction	4	1	2
Other deductions	(14)	(12)	(12)
TOTAL OTHER INCOME	(5)	11	1
INCOME BEFORE INTEREST AND INCOME TAX EXPENSE	2,242	2,150	2,061
INTEREST EXPENSE
Interest on long-term debt	567	523	511
Other interest	19	15	11
Allowance for borrowed funds used during construction	(2)	(1)	(1)
NET INTEREST EXPENSE	584	537	521
INCOME BEFORE INCOME TAX EXPENSE	1,658	1,613	1,540
INCOME TAX EXPENSE	574	555	520
NET INCOME	$ 1,084	$ 1,058	$ 1,020

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
NET INCOME	$ 1,193	$ 1,092	$ 1,062
OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAXES
Pension and other postretirement benefit plan liability adjustments, net of taxes	11	(20)	28
TOTAL OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAXES	11	(20)	28
COMPREHENSIVE INCOME	1,204	1,072	1,090
CECONY
NET INCOME	1,084	1,058	1,020
OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAXES
Pension and other postretirement benefit plan liability adjustments, net of taxes	2	(5)	3
TOTAL OTHER COMPREHENSIVE INCOME/(LOSS), NET OF TAXES	2	(5)	3
COMPREHENSIVE INCOME	$ 1,086	$ 1,053	$ 1,023

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES
NET INCOME	$ 1,193	$ 1,092	$ 1,062
PRINCIPAL NON-CASH CHARGES/(CREDITS) TO INCOME
Depreciation and amortization	1,130	1,071	1,024
Deferred income taxes	653	518	40
Rate case amortization and accruals	(52)	121	21
Common equity component of allowance for funds used during construction	(5)	(2)	(4)
Net derivative (gains)/losses	3	128	(74)
Pre-tax gains on termination of LILO transactions	0	0	(95)
Pre-tax gain on sale of solar electric production projects	0	(45)	0
Other non-cash items, net	77	(35)	91
CHANGES IN ASSETS AND LIABILITIES
Accounts receivable - customers	96	44	(29)
Special deposits	5	312	(257)
Materials and supplies, including fuel oil and gas in storage	22	(10)	(33)
Other receivables and other current assets	(32)	4	34
Income taxes receivable	58	(224)	0
Prepayments	(14)	(27)	23
Accounts payable	(79)	(9)	(118)
Pensions and retiree benefits obligations, net	756	822	829
Pensions and retiree benefits contributions	(756)	(584)	(887)
Accrued taxes	(10)	(404)	314
Accrued interest	4	(113)	96
Superfund and environmental remediation costs, net	22	28	(4)
Distributions from equity investments	31	0	0
Deferred charges, noncurrent assets and other regulatory assets	(111)	(361)	(162)
Deferred credits and other regulatory liabilities	182	498	637
Other current and noncurrent liabilities	104	7	44
NET CASH FLOWS FROM OPERATING ACTIVITIES	3,277	2,831	2,552
INVESTING ACTIVITIES
Utility construction expenditures	(2,562)	(2,239)	(2,339)
Cost of removal less salvage	(219)	(216)	(217)
Non-utility construction expenditures	(492)	(180)	(199)
Investments in/acquisitions of renewable electric production projects	(299)	(293)	(175)
Proceeds from grants related to solar electric production projects	0	36	93
Proceeds from sale of solar electric production projects	0	108	0
Restricted cash	(13)	15	(22)
Proceeds from the termination of LILO transactions	0	0	200
Other investing activities	(72)	10	0
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,657)	(2,759)	(2,659)
FINANCING ACTIVITIES
Net issuance/(payment) of short-term debt	729	(651)	912
Issuance of long-term debt	1,147	1,850	919
Retirement of long-term debt	(500)	(480)	(709)
Debt issuance costs	(15)	(17)	(6)
Common stock dividends	(733)	(739)	(721)
Issuance of common shares for stock plans, net of repurchases	1	(10)	(8)
NET CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES	629	(47)	387
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD	249	25	280
BALANCE AT BEGINNING OF PERIOD	699	674	394
BALANCE AT END OF PERIOD	948	699	674
LESS: HELD FOR SALE	4	0	0
BALANCE AT BEGINNING OF PERIOD	699	674
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	944	699	674
Cash paid/(received) during the period for:
Interest	597	561	574
Income taxes	(36)	633	69
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Construction expenditures in accounts payable	279	179	174
Issuance of common shares for dividend reinvestment	28	11	10
CECONY
OPERATING ACTIVITIES
NET INCOME	1,084	1,058	1,020
PRINCIPAL NON-CASH CHARGES/(CREDITS) TO INCOME
Depreciation and amortization	1,040	991	946
Deferred income taxes	449	331	222
Rate case amortization and accruals	(74)	102	10
Common equity component of allowance for funds used during construction	(4)	(1)	(2)
Other non-cash items, net	(27)	(33)	(80)
CHANGES IN ASSETS AND LIABILITIES
Accounts receivable - customers	87	59	(15)
Materials and supplies, including fuel oil and gas in storage	24	(12)	(15)
Other receivables and other current assets	38	48	(30)
Accounts receivables from affiliated companies	(58)	(13)	(58)
Prepayments	13	(24)	(21)
Accounts payable	(51)	(57)	(81)
Accounts payable to affiliates	(11)	(22)	23
Pensions and retiree benefits obligations, net	714	742	803
Pensions and retiree benefits contributions	(703)	(544)	(830)
Accrued taxes	3	0	9
Accrued taxes to affiliated companies	(8)	(403)	198
Accrued interest	1	(22)	6
Superfund and environmental remediation costs, net	19	32	(4)
Deferred charges, noncurrent assets and other regulatory assets	(150)	(334)	(148)
Deferred credits and other regulatory liabilities	379	475	666
Other current and noncurrent liabilities	54	57	24
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,819	2,430	2,643
INVESTING ACTIVITIES
Utility construction expenditures	(2,410)	(2,094)	(2,207)
Cost of removal less salvage	(212)	(210)	(210)
Restricted cash	(16)	0	0
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(2,638)	(2,304)	(2,417)
FINANCING ACTIVITIES
Net issuance/(payment) of short-term debt	583	(760)	789
Issuance of long-term debt	650	1,850	700
Retirement of long-term debt	(350)	(475)	(700)
Debt issuance costs	(7)	(17)	(7)
Capital contribution by parent	13	0	0
Dividend to parent	(872)	(712)	(728)
NET CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES	17	(114)	54
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD	198	12	280
BALANCE AT BEGINNING OF PERIOD	645	633	353
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	843	645	633
Cash paid/(received) during the period for:
Interest	554	504	500
Income taxes	163	748	163
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Construction expenditures in accounts payable	$ 210	$ 151	$ 116

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and temporary cash investments	$ 944	$ 699
Special deposits	3	8
Accounts receivable - customers, less allowance for uncollectible accounts	1,052	1,201
Other receivables, less allowance for uncollectible accounts	304	133
Income taxes receivable	166	224
Accrued unbilled revenue	360	500
Fuel oil, gas in storage, materials and supplies, at average cost	350	372
Prepayments	177	163
Regulatory assets	132	138
Assets held for sale	157	0
Other current assets	191	278
TOTAL CURRENT ASSETS	3,836	3,716
INVESTMENTS	884	816
UTILITY PLANT, AT ORIGINAL COST
General	2,622	2,465
TOTAL	38,174	35,909
Less: Accumulated depreciation	8,044	7,614
Net	30,130	28,295
Construction work in progress	1,003	1,031
NET UTILITY PLANT	31,133	29,326
NON-UTILITY PLANT
Non-utility property, less accumulated depreciation	832	388
Construction work in progress	244	113
NET PLANT	32,209	29,827
OTHER NONCURRENT ASSETS
Goodwill	429	429
Intangible assets, less accumulated amortization of $4 in 2015 and 2014	2	3
Regulatory assets	8,096	9,142
Other deferred charges and noncurrent assets	186	138
TOTAL OTHER NONCURRENT ASSETS	8,713	9,712
TOTAL ASSETS	45,642	44,071
CURRENT LIABILITIES
Long-term debt due within one year	739	560
Notes payable	1,529	800
Accounts payable	1,008	1,035
Customer deposits	354	344
Accrued taxes	62	72
Accrued interest	136	132
Accrued wages	97	95
Fair value of derivative liabilities	66	64
Regulatory liabilities	115	163
Liabilities held for sale	89	0
Other current liabilities	525	492
TOTAL CURRENT LIABILITIES	4,720	3,757
NONCURRENT LIABILITIES
Provision for injuries and damages	185	182
Pensions and retiree benefits	2,911	3,914
Superfund and other environmental costs	765	764
Asset retirement obligations	242	188
Fair value of derivative liabilities	39	13
Deferred income taxes and unamortized investment tax credits	9,537	8,948
Regulatory liabilities	1,977	1,993
Other deferred credits and noncurrent liabilities	199	181
TOTAL NONCURRENT LIABILITIES	15,855	16,183
LONG-TERM DEBT	12,006	11,546
EQUITY
Common shareholders’ equity	13,052	12,576
Noncontrolling interest	9	9
TOTAL EQUITY (See Statement of Equity)	13,061	12,585
TOTAL LIABILITIES AND EQUITY	45,642	44,071
CECONY
CURRENT ASSETS
Cash and temporary cash investments	843	645
Special deposits	2	2
Accounts receivable - customers, less allowance for uncollectible accounts	987	1,064
Other receivables, less allowance for uncollectible accounts	70	71
Accrued unbilled revenue	327	384
Accounts receivable from affiliated companies	190	132
Fuel oil, gas in storage, materials and supplies, at average cost	288	312
Prepayments	113	126
Regulatory assets	121	132
Other current assets	131	158
TOTAL CURRENT ASSETS	3,072	3,026
INVESTMENTS	286	271
UTILITY PLANT, AT ORIGINAL COST
General	2,411	2,265
TOTAL	35,766	33,584
Less: Accumulated depreciation	7,378	6,970
Net	28,388	26,614
Construction work in progress	922	971
NET UTILITY PLANT	29,310	27,585
NON-UTILITY PLANT
Non-utility property, less accumulated depreciation	5	5
NET PLANT	29,315	27,590
OTHER NONCURRENT ASSETS
Goodwill	245	245
Regulatory assets	7,482	8,457
Other deferred charges and noncurrent assets	75	99
TOTAL OTHER NONCURRENT ASSETS	7,557	8,556
TOTAL ASSETS	40,230	39,443
CURRENT LIABILITIES
Long-term debt due within one year	650	350
Notes payable	1,033	450
Accounts payable	771	802
Accounts payable to affiliated companies	12	23
Customer deposits	339	330
Accrued taxes	49	46
Accrued taxes to affiliated companies	2	10
Accrued interest	118	117
Accrued wages	88	84
Fair value of derivative liabilities	50	48
Regulatory liabilities	84	118
Other current liabilities	443	415
TOTAL CURRENT LIABILITIES	3,639	2,793
NONCURRENT LIABILITIES
Provision for injuries and damages	178	176
Pensions and retiree benefits	2,565	3,493
Superfund and other environmental costs	665	666
Asset retirement obligations	234	185
Fair value of derivative liabilities	36	10
Deferred income taxes and unamortized investment tax credits	8,755	8,163
Regulatory liabilities	1,789	1,837
Other deferred credits and noncurrent liabilities	167	144
TOTAL NONCURRENT LIABILITIES	14,389	14,674
LONG-TERM DEBT	10,787	10,788
EQUITY
Common shareholders’ equity	11,415	11,188
TOTAL LIABILITIES AND EQUITY	40,230	39,443
Electric
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	26,358	25,091
Electric \| CECONY
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	24,828	23,599
Gas
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	6,858	6,102
Gas \| CECONY
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	6,191	5,469
Steam
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	2,336	2,251
Steam \| CECONY
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	$ 2,336	$ 2,251

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts receivable - customers, allowance for uncollectible accounts	$ 85	$ 96
Other receivables, allowance for uncollectible accounts	11	10
Non-utility property, accumulated depreciation	95	91
Intangible assets, accumulated amortization	4	4
CECONY
Accounts receivable - customers, allowance for uncollectible accounts	80	90
Other receivables, allowance for uncollectible accounts	11	8
Non-utility property, accumulated depreciation	$ 25	$ 25

Consolidated Statement of Statement/Shareholders' Equity - USD ($) shares in Millions	Total	CECONY	Common Stock	Common Stock CECONY	Additional Paid-In Capital	Additional Paid-In Capital CECONY	Retained Earnings	Retained Earnings CECONY	Repurchased Con Edison Stock CECONY	Treasury Stock	Capital Stock Expense	Capital Stock Expense CECONY	Accumulated Other Comprehensive Income/(Loss)	Accumulated Other Comprehensive Income/(Loss) CECONY	Noncontrolling Interest
BALANCE at Dec. 31, 2012	$ 11,869,000,000		$ 32,000,000		$ 4,991,000,000		$ 7,997,000,000			$ (1,037,000,000)	$ (61,000,000)		$ (53,000,000)
BALANCE at Dec. 31, 2012		$ 10,552,000,000		$ 589,000,000		$ 4,234,000,000		$ 6,761,000,000	$ (962,000,000)			$ (61,000,000)		$ (9,000,000)
BALANCE (in shares) at Dec. 31, 2012			293	235						23
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,062,000,000	1,020,000,000					1,062,000,000	1,020,000,000
Common stock dividends	(721,000,000)	(728,000,000)					(721,000,000)	(728,000,000)
Issuance of common shares for stock plans, net of repurchases	7,000,000				4,000,000					$ 3,000,000
Issuance of common shares for stock plans, net of repurchases (in shares)			0							0
Other comprehensive income (loss)	28,000,000	3,000,000											28,000,000	3,000,000
BALANCE at Dec. 31, 2013		10,847,000,000		$ 589,000,000		4,234,000,000		7,053,000,000	(962,000,000)			(61,000,000)		(6,000,000)
BALANCE at Dec. 31, 2013	12,245,000,000		$ 32,000,000		4,995,000,000		8,338,000,000			$ (1,034,000,000)	$ (61,000,000)		(25,000,000)		$ 0
BALANCE (in shares) at Dec. 31, 2013			293	235						23
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,092,000,000	1,058,000,000					1,092,000,000	1,058,000,000
Common stock dividends	(739,000,000)	(712,000,000)					(739,000,000)	(712,000,000)
Issuance of common shares for stock plans, net of repurchases	(2,000,000)				(4,000,000)					$ 2,000,000
Issuance of common shares for stock plans, net of repurchases (in shares)			0							0
Other comprehensive income (loss)	(20,000,000)	(5,000,000)											(20,000,000)	(5,000,000)
BALANCE at Dec. 31, 2014	12,576,000,000	$ 11,188,000,000		$ 589,000,000		4,234,000,000		7,399,000,000	(962,000,000)			(61,000,000)		(11,000,000)
BALANCE at Dec. 31, 2014	$ 12,585,000,000		$ 32,000,000		4,991,000,000		8,691,000,000			$ (1,032,000,000)	(61,000,000)		(45,000,000)		9,000,000
BALANCE (in shares) at Dec. 31, 2014	293	235	293	235						23
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling interest	$ 9,000,000														9,000,000
Net income	1,193,000,000	$ 1,084,000,000					1,193,000,000	1,084,000,000
Common stock dividends	(761,000,000)	(872,000,000)					(761,000,000)	(872,000,000)
Capital contribution by parent		13,000,000				13,000,000
Issuance of common shares for stock plans, net of repurchases	33,000,000				39,000,000					$ (6,000,000)
Issuance of common shares for stock plans, net of repurchases (in shares)			0							0
Other comprehensive income (loss)	11,000,000	2,000,000											11,000,000	2,000,000
BALANCE at Dec. 31, 2015	13,052,000,000	$ 11,415,000,000		$ 589,000,000		$ 4,247,000,000		$ 7,611,000,000	$ (962,000,000)			$ (61,000,000)		$ (9,000,000)
BALANCE at Dec. 31, 2015	$ 13,061,000,000		$ 32,000,000		$ 5,030,000,000		$ 9,123,000,000			$ (1,038,000,000)	$ (61,000,000)		$ (34,000,000)		9,000,000
BALANCE (in shares) at Dec. 31, 2015	293	235	293	235						23
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling interest	$ 9,000,000														$ 9,000,000

Consolidated Statement of Capitalization - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Capitalization, Equity [Line Items]
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS	$ 13,086	$ 12,621
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS (Shares)	293	293
Pension plan liability adjustments, net of taxes	$ (31)	$ (42)
Unrealized gains/(losses) on derivatives qualified as cash flow hedges, less reclassification adjustment for gains/(losses) included in net income and reclassification adjustment for unrealized losses included in regulatory assets, net of taxes	(3)	(3)
TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS, NET OF TAXES	(34)	(45)
Equity	13,052	12,576
Noncontrolling interest	9	9
TOTAL EQUITY (See Statement of Equity)	13,061	12,585
CECONY
Schedule of Capitalization, Equity [Line Items]
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS	$ 11,424	$ 11,199
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS (Shares)	235	235
Pension plan liability adjustments, net of taxes	$ (6)	$ (8)
Unrealized gains/(losses) on derivatives qualified as cash flow hedges, less reclassification adjustment for gains/(losses) included in net income and reclassification adjustment for unrealized losses included in regulatory assets, net of taxes	(3)	(3)
TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS, NET OF TAXES	(9)	(11)
Equity	11,415	11,188
TOTAL COMMON SHAREHOLDER’S EQUITY (See Statement of Shareholder’s Equity)	$ 11,415	$ 11,188

Consolidated Statement of Capitalization - Long-term Debt - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL DEBENTURES

$ 11,110

$ 10,685

TOTAL TRANSITION BONDS

TOTAL TAX-EXEMPT DEBT

1,086

1,130

Other long-term debt

648

380

Unamortized debt expense

(91)

(85)

Unamortized debt discount

(22)

TOTAL

12,745

12,106

Less: Long-term debt due within one year

739

560

TOTAL LONG-TERM DEBT

12,006

11,546

TOTAL CAPITALIZATION

25,058

24,122

CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL DEBENTURES

10,450

10,150

TOTAL TAX-EXEMPT DEBT

1,086

Unamortized debt expense

(78)

(76)

Unamortized debt discount

(21)

(22)

TOTAL

11,437

11,138

Less: Long-term debt due within one year

650

350

TOTAL LONG-TERM DEBT

10,787

10,788

TOTAL CAPITALIZATION

$ 22,202

21,976

Debenture Series 2005C, 5.375% due 2015

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.375%

Debt instrument, fair value

$ 0

350

Debenture Series 2005C, 5.375% due 2015 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.375%

Debt instrument, fair value

$ 0

350

Debenture Series 2005A, 5.30% due 2015

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

Debt instrument, fair value

$ 0

Debenture Series 2010A, 2.50% Due 2015

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.50%

Debt instrument, fair value

$ 0

Debenture Series 2006A, 5.45% Due 2016

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.45%

Debt instrument, fair value

$ 75

Debenture Series 2006C, 5.50% Due 2016

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

Debt instrument, fair value

$ 400

400

Debenture Series 2006C, 5.50% Due 2016 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

Debt instrument, fair value

$ 400

400

Debenture Series 2006D, 5.30% Due 2016

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

Debt instrument, fair value

$ 250

250

Debenture Series 2006D, 5.30% Due 2016 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

Debt instrument, fair value

$ 250

250

Debenture Series 2008A, 5.85% Due 2018

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.85%

Debt instrument, fair value

$ 600

600

Debenture Series 2008A, 5.85% Due 2018 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.85%

Debt instrument, fair value

$ 600

600

Debenture Series 2008A, 6.15% Due 2018

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.15%

Debt instrument, fair value

$ 50

Debenture Series 2008C, 7.125% Due 2018

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

7.125%

Debt instrument, fair value

$ 600

600

Debenture Series 2008C, 7.125% Due 2018 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

7.125%

Debt instrument, fair value

$ 600

600

Debenture Series 2009A, 4.96% Due 2019

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.96%

Debt instrument, fair value

$ 60

Debenture Series 2009B, 6.65% Due 2019

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.65%

Debt instrument, fair value

$ 475

475

Debenture Series 2009B, 6.65% Due 2019 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.65%

Debt instrument, fair value

$ 475

475

Debenture Series 2010A, 4.45% Due 2020

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

Debt instrument, fair value

$ 350

350

Debenture Series 2010A, 4.45% Due 2020 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

Debt instrument, fair value

$ 350

350

Debenture Series 2014B, 3.30% Due 2024

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.30%

Debt instrument, fair value

$ 250

250

Debenture Series 2014B, 3.30% Due 2024 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.30%

Debt instrument, fair value

$ 250

250

Debenture Series 1997F, 6.50% Due 2027

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.50%

Debt instrument, fair value

$ 80

Debenture Series 2003A, 5.875% Due 2033

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.875%

Debt instrument, fair value

$ 175

175

Debenture Series 2003A, 5.875% Due 2033 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.875%

Debt instrument, fair value

$ 175

175

Debenture Series 2003C, 5.10% Due 2033

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.10%

Debt instrument, fair value

$ 200

200

Debenture Series 2003C, 5.10% Due 2033 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.10%

Debt instrument, fair value

$ 200

200

Debenture Series 2004B, 5.70% Due 2034

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

Debt instrument, fair value

$ 200

200

Debenture Series 2004B, 5.70% Due 2034 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

Debt instrument, fair value

$ 200

200

Debenture Series 2005A, 5.30% Due 2035

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

Debt instrument, fair value

$ 350

350

Debenture Series 2005A, 5.30% Due 2035 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

Debt instrument, fair value

$ 350

350

Debenture Series 2005B, 5.25% Due 2035

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.25%

Debt instrument, fair value

$ 125

125

Debenture Series 2005B, 5.25% Due 2035 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.25%

Debt instrument, fair value

$ 125

125

Debenture Series 2006A, 5.85% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.85%

Debt instrument, fair value

$ 400

400

Debenture Series 2006A, 5.85% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.85%

Debt instrument, fair value

$ 400

400

Debenture Series 2006B, 6.20% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.20%

Debt instrument, fair value

$ 400

400

Debenture Series 2006B, 6.20% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.20%

Debt instrument, fair value

$ 400

400

Debenture Series 2006E, 5.70% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

Debt instrument, fair value

$ 250

250

Debenture Series 2006E, 5.70% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

Debt instrument, fair value

$ 250

250

Debenture Series 2007A, 6.30% Due 2037

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.30%

Debt instrument, fair value

$ 525

525

Debenture Series 2007A, 6.30% Due 2037 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.30%

Debt instrument, fair value

$ 525

525

Debenture Series 2008B, 6.75% Due 2038

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.75%

Debt instrument, fair value

$ 600

600

Debenture Series 2008B, 6.75% Due 2038 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.75%

Debt instrument, fair value

$ 600

600

Debenture Series 2009B, 6.00% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.00%

Debt instrument, fair value

$ 60

Debenture Series 2009C, 5.50% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

Debt instrument, fair value

$ 600

600

Debenture Series 2009C, 5.50% Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

Debt instrument, fair value

$ 600

600

Debenture Series 2010B, 5.70% Due 2040

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

Debt instrument, fair value

$ 350

350

Debenture Series 2010B, 5.70% Due 2040 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

Debt instrument, fair value

$ 350

350

Debenture Series 2010B, 5.50% Due 2040

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

Debt instrument, fair value

$ 115

115

Debenture Series 2012A, 4.20% Due 2042

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.20%

Debt instrument, fair value

$ 400

400

Debenture Series 2012A, 4.20% Due 2042 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.20%

Debt instrument, fair value

$ 400

400

Debenture Series 2013A, 3.95% Due 2043

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.95%

Debt instrument, fair value

$ 700

700

Debenture Series 2013A, 3.95% Due 2043 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.95%

Debt instrument, fair value

$ 700

700

Debenture Series 2014A, 4.45% Due 2044

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

Debt instrument, fair value

$ 850

850

Debenture Series 2014A, 4.45% Due 2044 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

Debt instrument, fair value

$ 850

850

Debenture Series 2015A, 4.50% due 2045

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.50%

Debt instrument, fair value

$ 650

Debenture Series 2015A, 4.50% due 2045 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.50%

Debt instrument, fair value

$ 650

Debenture Series 2015A, 4.95% due 2045

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.95%

Debt instrument, fair value

$ 120

Debenture Series 2015B, 4.69% due 2045

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.69%

Debt instrument, fair value

$ 100

Debenture Series 2014C, 4.625% Due 2054

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.625%

Debt instrument, fair value

$ 750

750

Debenture Series 2014C, 4.625% Due 2054 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.625%

Debt instrument, fair value

$ 750

750

Debenture Series 2004-1, 5.22% Due 2019

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

5.22%

Debt instrument, fair value

^[1]

$ 14

Debenture Series 1995, 0.00% Due 2015

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[2],[3]

0.00%

Debt instrument, fair value

^[2],[3]

$ 0

Tax Exempt Debt Series 2004B-1, 0.42% Due 2032

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.42%

Debt instrument, fair value

^[3]

$ 127

127

Tax Exempt Debt Series 2004B-1, 0.42% Due 2032 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.42%

Debt instrument, fair value

^[1]

$ 127

127

Tax Exempt Debt Series 1999A, .34% Due 2034

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.34%

Debt instrument, fair value

^[3]

$ 293

293

Tax Exempt Debt Series 1999A, .34% Due 2034 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.34%

Debt instrument, fair value

^[1]

$ 293

293

Tax Exempt Debt Series 2004B Series 2, .44% Due 2035

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.44%

Debt instrument, fair value

^[3]

$ 20

Tax Exempt Debt Series 2004B Series 2, .44% Due 2035 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.44%

Debt instrument, fair value

^[1]

$ 20

Tax-Exempt Debt Series 2001B, 0.27% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.27%

Debt instrument, fair value

^[3]

$ 98

Tax-Exempt Debt Series 2001B, 0.27% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.27%

Debt instrument, fair value

^[1]

$ 98

Tax-Exempt Debt Series 2010A, 0.01% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.01%

Debt instrument, fair value

^[3]

$ 225

225

Tax-Exempt Debt Series 2010A, 0.01% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.01%

Debt instrument, fair value

^[1]

$ 225

225

Tax-Exempt Debt Series 2004A, 0.36% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.36%

Debt instrument, fair value

^[3]

$ 98

Tax-Exempt Debt Series 2004A, 0.36% Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.36%

Debt instrument, fair value

^[1]

$ 98

Tax-Exempt Debt Series 2004C, 0.01% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.01%

Debt instrument, fair value

^[3]

$ 99

Tax-Exempt Debt Series 2004C, 0.01% Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.01%

Debt instrument, fair value

^[1]

$ 99

Tax-Exempt Debt Series 2005A, 0.01% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[3]

0.01%

Debt instrument, fair value

^[3]

$ 126

126

Tax-Exempt Debt Series 2005A, 0.01% Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

^[1]

0.01%

Debt instrument, fair value

^[1]

$ 126

[1]	The final date to pay the entire remaining unpaid principal balance, if any, of all outstanding bonds is May 17, 2021.
[2]	Issued for O&R pollution control financing.
[3]	Rates are to be reset weekly or by auction held every 35 days; December 31, 2015 rates shown.

General	12 Months Ended
General	Dec. 31, 2015
General	General These combined notes accompany and form an integral part of the separate consolidated financial statements of each of the two separate registrants: Consolidated Edison, Inc. and its subsidiaries (Con Edison) and Consolidated Edison Company of New York, Inc. and its subsidiaries (CECONY). CECONY is a subsidiary of Con Edison and as such its financial condition and results of operations and cash flows, which are presented separately in the CECONY consolidated financial statements, are also consolidated, along with those of Con Edison’s other utility subsidiary, Orange and Rockland Utilities, Inc. (O&R), and Con Edison’s competitive energy businesses (discussed below) in Con Edison’s consolidated financial statements. The term “Utilities” is used in these notes to refer to CECONY and O&R. As used in these notes, the term “Companies” refers to Con Edison and CECONY and, except as otherwise noted, the information in these combined notes relates to each of the Companies. However, CECONY makes no representation as to information relating to Con Edison or the subsidiaries of Con Edison other than itself. Con Edison has two regulated utility subsidiaries: CECONY and O&R. CECONY provides electric service and gas service in New York City and Westchester County. The company also provides steam service in parts of Manhattan. O&R, along with its regulated utility subsidiaries, provides electric service in southeastern New York and adjacent areas of northern New Jersey and eastern Pennsylvania (see Note U) and gas service in southeastern New York and adjacent areas of eastern Pennsylvania. Con Edison has the following competitive energy businesses: Consolidated Edison Solutions, Inc. (Con Edison Solutions), a company which sells to retail customers electricity purchased in wholesale markets (see Note U), enters into related hedging transactions and also provides energy-related products and services to retail customers; Consolidated Edison Energy, Inc. (Con Edison Energy), a company that provides energy-related products and services to wholesale customers; and Consolidated Edison Development, Inc. (Con Edison Development), a company that develops, owns and operates renewable and energy infrastructure projects. In addition, in 2014 Con Edison formed Consolidated Edison Transmission LLC (CET Electric) to invest in an electric transmission company. In January 2016, Con Edison transferred CET Electric to another wholly-owned subsidiary of Con Edison, Con Edison Transmission, Inc. (Con Edison Transmission). See information about CET Electric under “Guarantees” in Note H. In January 2016, Con Edison Transmission formed Con Edison Gas Midstream, LLC (CET Gas) to invest in gas transmission projects.
CECONY
General	General These combined notes accompany and form an integral part of the separate consolidated financial statements of each of the two separate registrants: Consolidated Edison, Inc. and its subsidiaries (Con Edison) and Consolidated Edison Company of New York, Inc. and its subsidiaries (CECONY). CECONY is a subsidiary of Con Edison and as such its financial condition and results of operations and cash flows, which are presented separately in the CECONY consolidated financial statements, are also consolidated, along with those of Con Edison’s other utility subsidiary, Orange and Rockland Utilities, Inc. (O&R), and Con Edison’s competitive energy businesses (discussed below) in Con Edison’s consolidated financial statements. The term “Utilities” is used in these notes to refer to CECONY and O&R. As used in these notes, the term “Companies” refers to Con Edison and CECONY and, except as otherwise noted, the information in these combined notes relates to each of the Companies. However, CECONY makes no representation as to information relating to Con Edison or the subsidiaries of Con Edison other than itself. Con Edison has two regulated utility subsidiaries: CECONY and O&R. CECONY provides electric service and gas service in New York City and Westchester County. The company also provides steam service in parts of Manhattan. O&R, along with its regulated utility subsidiaries, provides electric service in southeastern New York and adjacent areas of northern New Jersey and eastern Pennsylvania (see Note U) and gas service in southeastern New York and adjacent areas of eastern Pennsylvania. Con Edison has the following competitive energy businesses: Consolidated Edison Solutions, Inc. (Con Edison Solutions), a company which sells to retail customers electricity purchased in wholesale markets (see Note U), enters into related hedging transactions and also provides energy-related products and services to retail customers; Consolidated Edison Energy, Inc. (Con Edison Energy), a company that provides energy-related products and services to wholesale customers; and Consolidated Edison Development, Inc. (Con Edison Development), a company that develops, owns and operates renewable and energy infrastructure projects. In addition, in 2014 Con Edison formed Consolidated Edison Transmission LLC (CET Electric) to invest in an electric transmission company. In January 2016, Con Edison transferred CET Electric to another wholly-owned subsidiary of Con Edison, Con Edison Transmission, Inc. (Con Edison Transmission). See information about CET Electric under “Guarantees” in Note H. In January 2016, Con Edison Transmission formed Con Edison Gas Midstream, LLC (CET Gas) to invest in gas transmission projects.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Principles of Consolidation

The Companies’ consolidated financial statements include the accounts of their respective majority-owned subsidiaries, and variable interest entities (see Note Q), as required. All intercompany balances and transactions have been eliminated.

Accounting Policies

The accounting policies of Con Edison and its subsidiaries conform to generally accepted accounting principles in the United States of America (GAAP). For the Utilities, these accounting principles include the accounting rules for regulated operations and the accounting requirements of the Federal Energy Regulatory Commission (FERC) and the state regulators having jurisdiction.

The accounting rules for regulated operations specify the economic effects that result from the causal relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under the accounting rules for regulated operations. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under the accounting rules for regulated operations.

The Utilities’ principal regulatory assets and liabilities are detailed in Note B. The Utilities are receiving or being credited with a return on all of their regulatory assets for which a cash outflow has been made, and are paying or being charged with a return on all of their regulatory liabilities for which a cash inflow has been received. The Utilities’ regulatory assets and liabilities will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable state regulators.

Other significant accounting policies of the Companies are referenced below in this Note A and in the notes that follow.

Plant and Depreciation

Utility Plant

Utility plant is stated at original cost. The cost of repairs and maintenance is charged to expense and the cost of betterments is capitalized. The capitalized cost of additions to utility plant includes indirect costs such as engineering, supervision, payroll taxes, pensions, other benefits and an allowance for funds used during construction (AFUDC). The original cost of property is charged to expense over the estimated useful lives of the assets. Upon retirement, the original cost of property is charged to accumulated depreciation. See Note R.

Rates used for AFUDC include the cost of borrowed funds and a reasonable rate of return on the Utilities’ own funds when so used, determined in accordance with regulations of the FERC or the state public utility regulatory authority having jurisdiction. The rate is compounded semiannually, and the amounts applicable to borrowed funds are treated as a reduction of interest charges, while the amounts applicable to the Utilities’ own funds are credited to other income (deductions). The AFUDC rates for CECONY were 4.4 percent, 1.6 percent and 4.0 percent for 2015, 2014 and 2013, respectively. The AFUDC rates for O&R were 0.4 percent, 2.6 percent and 5.7 percent for 2015, 2014 and 2013, respectively.

The Utilities generally compute annual charges for depreciation using the straight-line method for financial statement purposes, with rates based on average service lives and net salvage factors. The average depreciation rates for CECONY were 3.1 percent, 3.1 percent and 3.2 percent for 2015, 2014 and 2013, respectively. The average depreciation rates for O&R were 3.0 percent, 2.9 percent and 2.8 percent for 2015, 2014 and 2013, respectively.

The estimated lives for utility plant for CECONY range from 5 to 85 years for electric and gas, 5 to 80 years for steam and 5 to 55 years for general plant. For O&R, the estimated lives for utility plant range from 5 to 75 years for electric and gas and 5 to 50 years for general plant.

At December 31, 2015 and 2014, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Electric
Generation	$459	$451	$459	$451
Transmission	3,045	2,956	2,833	2,744
Distribution	17,244	16,361	16,394	15,531
Gas (a)	5,698	5,006	5,196	4,530
Steam	1,849	1,795	1,849	1,795
General	1,758	1,650	1,592	1,498
Held for future use	77	76	65	65
Construction work in progress	1,003	1,031	922	971
Net Utility Plant	$31,133	$29,326	$29,310	$27,585

(a) Primarily distribution.

Under the Utilities’ rate plans, the aggregate annual depreciation allowance in effect at December 31, 2015 was $1,110 million, including $1,050 million under CECONY’s electric, gas and steam rate plans that have been approved by the New York State Public Service Commission (NYSPSC).

Non-Utility Plant

Non-utility plant is stated at original cost. For Con Edison, non-utility plant consists primarily of the competitive energy businesses’ renewable electric production and gas storage. For the Utilities, non-utility plant consists of land and conduit for telecommunication use. Depreciation on these assets is computed using the straight-line method for financial statement purposes over their estimated useful lives, which range from 3 to 30 years.

Goodwill

Con Edison tests goodwill for impairment at least annually. There is an option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying a two-step, quantitative goodwill impairment test. However Con Edison has not elected to perform the qualitative assessment and exclusively applies the two-step quantitative approach. The first step of the goodwill impairment test compares the estimated fair value of a reporting unit with its carrying value, including goodwill. If the estimated fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is considered not impaired. If the carrying value exceeds the estimated fair value of the reporting unit, the second step is performed to measure the amount of impairment loss, if any. The second step requires a calculation of the implied fair value of goodwill. See Note K.

Impairments

Con Edison evaluates the impairment of long-lived assets, based on projections of undiscounted future cash flows, whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event an evaluation indicates that such cash flows cannot be expected to be sufficient to fully recover the assets, the assets are written down to their estimated fair value. In 2015, Con Edison recorded a $5 million impairment charge on Pike County Light & Power Company (Pike) assets held for sale. See Note U. No impairment charges on long-lived assets were recognized in 2014 or 2013.

Revenues

The Utilities and Con Edison Solutions recognize revenues for energy service on a monthly billing cycle basis. The Utilities defer over a 12-month period net interruptible gas revenues, other than those authorized by the NYSPSC to be retained by the Utilities, for refund to firm gas sales and transportation customers. The Utilities and Con Edison Solutions accrue revenues at the end of each month for estimated energy service not yet billed to customers.

CECONY’s electric and gas rate plans and O&R’s New York electric and gas rate plans each contain a revenue decoupling mechanism under which the company’s actual energy delivery revenues are compared with the authorized delivery revenues and the difference accrued, with interest, for refund to, or recovery from, customers, as applicable. See “Rate Plans” in Note B.

The NYSPSC requires utilities to record gross receipts tax revenues and expenses on a gross income statement presentation basis (i.e., included in both revenue and expense). The recovery of these taxes is generally provided for in the revenue requirement within each of the respective NYSPSC approved rate plans. Total excise taxes (inclusive of gross receipts taxes) recorded in operating revenues were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$354	$365	$354
CECONY	331	343	329

Recoverable Energy Costs

The Utilities generally recover all of their prudently incurred fuel, purchased power and gas costs, including hedging gains and losses, in accordance with rate provisions approved by the applicable state public utility regulators. If the actual energy supply costs for a given month are more or less than the amounts billed to customers for that month, the difference in most cases is recoverable from or refundable to customers. Differences between actual and billed electric and steam supply costs and costs of its electric demand management programs are generally deferred for charge or refund to customers during the next billing cycle (normally within one or two months). For the Utilities’ gas costs, differences between actual and billed gas costs during the 12-month period ending each August are charged or refunded to customers during a subsequent 12-month period.

New York Independent System Operator (NYISO)

The Utilities purchase electricity through the wholesale electricity market administered by the NYISO. The difference between purchased power and related costs initially billed to the Utilities by the NYISO and the actual cost of power subsequently calculated by the NYISO is refunded by the NYISO to the Utilities, or paid to the NYISO by the Utilities. The reconciliation payments or receipts are recoverable from or refundable to the Utilities’ customers.

Certain other payments to or receipts from the NYISO are also subject to reconciliation, with shortfalls or amounts in excess of specified rate allowances recoverable from or refundable to customers. These include proceeds from the sale through the NYISO of transmission rights on CECONY’s transmission system (transmission congestion contracts or TCCs).

Temporary Cash Investments

Temporary cash investments are short-term, highly-liquid investments that generally have maturities of three months or less at the date of purchase. They are stated at cost, which approximates market. The Companies consider temporary cash investments to be cash equivalents.

Investments

Investments consist primarily of the investments of Con Edison’s competitive energy businesses, which are accounted for under the equity method (depending on the subsidiaries’ percentage ownership). Utilities’ investments are recorded at fair value and include the investments of the deferred income plan and the supplemental retirement income plan in trust-owned life insurance assets.

Pension and Other Postretirement Benefits

The accounting rules for retirement benefits require an employer to recognize an asset or liability for the overfunded or underfunded status of its pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. The accounting rules generally require employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in accumulated other comprehensive income (OCI), net of tax. Such amounts will be adjusted as they are subsequently recognized as components of total periodic benefit cost or income pursuant to the current recognition and amortization provisions.

For the Utilities’ pension and other postretirement benefit plans, regulatory accounting treatment is generally applied in accordance with the accounting rules for regulated operations. Unrecognized prior service costs or credits and unrecognized actuarial gains and losses are recorded to regulatory assets or liabilities, rather than OCI. See Notes E and F.

The total periodic benefit costs are recognized in accordance with the accounting rules for retirement benefits. Investment gains and losses are recognized in expense over a 15-year period and other actuarial gains and losses are recognized in expense over a 10-year period, subject to the deferral provisions in the rate plans.

In accordance with the Statement of Policy issued by the NYSPSC and its current electric, gas and steam rate plans, CECONY defers for payment to or recovery from customers the difference between such expenses and the amounts for such expenses reflected in rates. Generally, O&R also defers such difference pursuant to its rate plans. See Note B.

The Companies calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected rate of return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. The accounting rules allow the MRV of plan assets to be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. The Companies use a calculated value when determining the MRV of the plan assets that adjusts for 20 percent of the difference between fair value and expected MRV of plan assets. This calculated value has the effect of stabilizing variability in assets to which the Companies apply the expected return.

Federal Income Tax

In accordance with the accounting rules for income taxes, the Companies have recorded an accumulated deferred federal income tax liability at current tax rates for temporary differences between the book and tax basis of assets and liabilities. In accordance with rate plans, the Utilities have recovered amounts from customers for a portion of the tax liability they will pay in the future as a result of the reversal or “turn-around” of these temporary differences. As to the remaining tax liability, in accordance with the accounting rules for regulated operations, the Utilities have established regulatory assets for the net revenue requirements to be recovered from customers for the related future tax expense. See Notes B and L. In 1993, the NYSPSC issued a Policy Statement approving accounting procedures consistent with the accounting rules for income taxes and providing assurances that these future increases in taxes will be recoverable in rates. See Note L.

Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties and applied as a reduction to future federal income tax expense.

Con Edison and its subsidiaries file a consolidated federal income tax return. The consolidated income tax liability is allocated to each member of the consolidated group using the separate return method. Each member pays or receives an amount based on its own taxable income or loss in accordance with tax sharing agreements among the members of the consolidated group. Tax loss carryforwards are allocated among members in accordance with consolidated tax return regulations.

State Income Tax

Con Edison and its subsidiaries file a combined New York State Corporation Business Franchise Tax Return. Similar to a federal consolidated income tax return, the income of all entities in the combined group is subject to New York State taxation, after adjustments for differences between federal and New York law and apportionment of income among the states in which the company does business. Each member’s share of the New York State tax is based on its own New York State taxable income or loss.

Research and Development Costs

Generally research and development costs are charged to operating expenses as incurred. Research and development costs were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$23	$22	$18
CECONY	22	20	16

Reclassification

Certain prior year amounts have been reclassified to conform with the current year presentation.

Earnings Per Common Share

Con Edison presents basic and diluted earnings per share on the face of its consolidated income statement. Basic earnings per share (EPS) are calculated by dividing earnings available to common shareholders (“Net income” on Con Edison’s consolidated income statement) by the weighted average number of Con Edison common shares outstanding during the period. In the calculation of diluted EPS, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock.

Potentially dilutive securities for Con Edison consist of restricted stock units, deferred stock units and stock options for which the average market price of the common shares for the period was greater than the exercise price. See Note M.

Basic and diluted EPS for Con Edison are calculated as follows:



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts/Shares in Millions)	2015	2014	2013
Net income	$1,193	$1,092	$1,062
Weighted average common shares outstanding – basic	293.0	292.9	292.9
Add: Incremental shares attributable to effect of potentially dilutive securities	1.4	1.1	1.5
Adjusted weighted average common shares outstanding – diluted	294.4	294.0	294.4
Net Income per common share – basic	$4.07	$3.73	$3.62
Net Income per common share – diluted	$4.05	$3.71	$3.61

The computation of diluted EPS for the years ended December 31, 2014 and 2013 exclude immaterial amounts of performance share awards that were not included because of their anti-dilutive effect.

Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Changes in Accumulated Other Comprehensive Income by Component

Changes to accumulated other comprehensive income (OCI) for Con Edison and CECONY are as follows:



(Millions of Dollars)	Con Edison	CECONY
Accumulated OCI, net of taxes, at December 31, 2013	$(25)	$(6)
OCI before reclassifications, net of tax of $18 and $4 for Con Edison and CECONY, respectively	(26)	(6)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) for Con Edison and CECONY, respectively (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2014	(20)	(5)
Accumulated OCI, net of taxes, at December 31, 2014 (a)	$(45)	$(11)
OCI before reclassifications, net of tax of $(3) for Con Edison	5	1
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) for Con Edison and CECONY, respectively (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2015	11	2
Accumulated OCI, net of taxes, at December 31, 2015 (a)	$(34)	$(9)

(a) Tax reclassified from accumulated OCI is reported in the income tax expense line item of the income statement.

(b) For the portion of unrecognized pension and other postretirement benefit costs relating to the regulated Utilities, costs are recorded into, and amortized out of, regulatory assets instead of OCI. The net actuarial losses and prior service costs recognized during the period are included in the computation of total periodic pension and other postretirement benefit cost. See Notes E and F.

CECONY

Summary of Significant Accounting Policies

Principles of Consolidation

Accounting Policies

Other significant accounting policies of the Companies are referenced below in this Note A and in the notes that follow.

Plant and Depreciation

Utility Plant

At December 31, 2015 and 2014, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Electric
Generation	$459	$451	$459	$451
Transmission	3,045	2,956	2,833	2,744
Distribution	17,244	16,361	16,394	15,531
Gas (a)	5,698	5,006	5,196	4,530
Steam	1,849	1,795	1,849	1,795
General	1,758	1,650	1,592	1,498
Held for future use	77	76	65	65
Construction work in progress	1,003	1,031	922	971
Net Utility Plant	$31,133	$29,326	$29,310	$27,585

(a) Primarily distribution.

Non-Utility Plant

Goodwill

Impairments

Revenues



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$354	$365	$354
CECONY	331	343	329

Recoverable Energy Costs

New York Independent System Operator (NYISO)

Temporary Cash Investments

Investments

Pension and Other Postretirement Benefits

Federal Income Tax

Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties and applied as a reduction to future federal income tax expense.

State Income Tax

Research and Development Costs

Generally research and development costs are charged to operating expenses as incurred. Research and development costs were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$23	$22	$18
CECONY	22	20	16

Reclassification

Certain prior year amounts have been reclassified to conform with the current year presentation.

Earnings Per Common Share

Basic and diluted EPS for Con Edison are calculated as follows:



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts/Shares in Millions)	2015	2014	2013
Net income	$1,193	$1,092	$1,062
Weighted average common shares outstanding – basic	293.0	292.9	292.9
Add: Incremental shares attributable to effect of potentially dilutive securities	1.4	1.1	1.5
Adjusted weighted average common shares outstanding – diluted	294.4	294.0	294.4
Net Income per common share – basic	$4.07	$3.73	$3.62
Net Income per common share – diluted	$4.05	$3.71	$3.61

The computation of diluted EPS for the years ended December 31, 2014 and 2013 exclude immaterial amounts of performance share awards that were not included because of their anti-dilutive effect.

Estimates

Changes in Accumulated Other Comprehensive Income by Component

Changes to accumulated other comprehensive income (OCI) for Con Edison and CECONY are as follows:



(Millions of Dollars)	Con Edison	CECONY
Accumulated OCI, net of taxes, at December 31, 2013	$(25)	$(6)
OCI before reclassifications, net of tax of $18 and $4 for Con Edison and CECONY, respectively	(26)	(6)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) for Con Edison and CECONY, respectively (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2014	(20)	(5)
Accumulated OCI, net of taxes, at December 31, 2014 (a)	$(45)	$(11)
OCI before reclassifications, net of tax of $(3) for Con Edison	5	1
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) for Con Edison and CECONY, respectively (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2015	11	2
Accumulated OCI, net of taxes, at December 31, 2015 (a)	$(34)	$(9)

(a) Tax reclassified from accumulated OCI is reported in the income tax expense line item of the income statement.

Regulatory Matters

12 Months Ended

Dec. 31, 2015

Regulatory Matters

Rate Plans

The Utilities provide service to New York customers according to the terms of tariffs approved by the NYSPSC. Tariffs for service to customers of O&R’s New Jersey and Pennsylvania (see Note U) regulated utility subsidiaries are approved by utility regulators in those states. The tariffs include schedules of rates for service that limit the rates charged by the Utilities to amounts that recover from their customers costs approved by the regulator, including capital costs, of providing service to customers as defined by the tariff. The tariffs implement rate plans adopted by state utility regulators in rate orders issued at the conclusion of rate proceedings. Pursuant to the Utilities’ rate plans, there generally can be no change to the charges to customers during the respective terms of the rate plans other than specified adjustments provided for in the rate plans. The Utilities’ rate plans each cover specified periods, but rates determined pursuant to a plan generally continue in effect until a new rate plan is approved by the state utility regulator.

Common provisions of the Utilities’ rate plans include:

Recoverable energy costs that allow the Utilities to recover on a current basis the costs for the energy they supply with no mark-up to their full-service customers.

Cost reconciliations that reconcile pension and other postretirement benefit costs, environmental remediation costs, property taxes, variable rate tax-exempt debt and certain other costs to amounts reflected in delivery rates for such costs. Utilities generally retain the right to petition for recovery or accounting deferral of extraordinary and material cost increases for items such as major storm events and provision is sometimes made for the utility to retain a share of cost reductions, for example, property tax refunds.

Revenue decoupling mechanisms that reconcile actual energy delivery revenues to the authorized delivery revenues approved by the NYSPSC. The difference is accrued with interest for refund to, or recovery from customers, as applicable.

Earnings sharing that require the Utilities to defer for customer benefit a portion of earnings over specified rates of return on common equity. There is no symmetric mechanism for earnings below specified rates of return on common equity.

Negative revenue adjustments for failure to meet certain performance standards relating to service, reliability, safety and other matters.

Net utility plant reconciliations that require deferral as a regulatory liability of the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates.

Rate base is, in general, the sum of the Utilities’ net plant and working capital less deferred taxes. For each rate plan, the NYSPSC uses a forecast of the average rate base for each year that new rates would be in effect (“rate year”). The New Jersey Board of Public Utilities (NJBPU) and the Pennsylvania Public Utility Commission (PAPUC) use the rate base balances that would exist at the beginning of the rate year.

Weighted average cost of capital is determined based on the authorized common equity ratio, return on common equity, cost of long-term debt and customer deposits reflected in each rate plan. For each rate plan, the revenues designed to provide the utility a return on invested capital for each rate year are determined by multiplying each utility rate base by its pre-tax weighted average cost of capital. The Utilities’ actual return on common equity will reflect their actual operations for each rate year, and may be more or less than the authorized return on equity reflected in their rate plans (and if more, may be subject to earnings sharing).

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	April 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $420 million Yr. 2 – $420 million Yr. 3 – $287 million(b)	Yr. 1 – $(76.2) million (c) Yr. 2 – $124.0 million (c) Yr. 3 – None
Amortizations to income of net regulatory (assets) and liabilities	$(75.3) million over three years	Yr. 1 and 2 – $(37) million (d) Yr. 3 - $123 million (d)
Other revenue sources	Retention of $120 million of annual transmission congestion revenues from the sale of transmission rights ($90 million for the period April 1, 2013 to December 31, 2013).	Retention of $90 million of annual transmission congestion revenues.
Revenue decoupling mechanisms	In 2012 and 2013, the company deferred for customer benefit $59 million and $34 million of revenues, respectively.	In 2014 and 2015, the company deferred for customer benefit $146 million and $98 million of revenues, respectively.
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power and fuel costs (e).
Negative revenue adjustments	Potential penalties (up to $350 million annually) if certain performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (f)	In 2012 and 2013, the company deferred $146 million of net regulatory liabilities and $35 million of net regulatory assets, respectively.	In 2014 and 2015, the company deferred $57 million and $26 million of net regulatory liabilities, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $13,818 million Yr. 2 – $14,742 million Yr. 3 – $15,414 million Enterprise resource project: Yr. 2 – $25 million; Yr. 3 -$115 million; Other: Yr. 1 – $1,487 million; Yr. 2 – $1,565 million; Yr. 3 – $1,650 million The company deferred an immaterial amount and $7 million as a regulatory liability in 2012 and 2013, respectively.	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred an immaterial amount and $17 million as a regulatory liability in 2014 and 2015, respectively.
Average rate base	Yr. 1 – $14,887 million Yr. 2 – $15,987 million Yr. 3 – $16,826 million	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million
Weighted average cost of capital (after-tax)	7.76 percent	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent
Authorized return on common equity	10.15 percent assuming the company achieved austerity measures of $27 million, $20 million and $13 million for Yrs. 1, 2 and 3, respectively. Austerity measures were achieved.	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent
Earnings sharing	Actual earnings above an annual earnings threshold of 11.15 percent for Yr. 1 and 10.65 percent for Yrs. 2 and 3 were to be applied to reduce regulatory assets for pensions and other postretirement benefits and other costs. Actual earnings were $17.5 million above the threshold for the period ended 2013.	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $44.4 million above the threshold for 2015.
Cost of long-term debt	5.65 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent
Common equity ratio	48 percent	48 percent


(a)	$249 million of annual revenues collected from electric customers will continue to be subject to potential refund following NYSPSC staff review of certain costs. See "Other Regulatory Matters" below. Revenues for 2014 through 2016 will include $21 million as funding for major storm reserve.


(b)	Temporary portion of the increase ($134 million) that was scheduled to go into effect April 1, 2012 was eliminated by the application of available credits.


(c)	The impact of these base rate changes were deferred which resulted in a $30 million regulatory liability at December 31, 2015.

(d)

Amounts reflect annual amortization of $107 million of the regulatory asset for deferred Superstorm Sandy and other major storm costs. The costs recoverable from customers were reduced by $4 million. The costs are no longer subject to NYSPSC staff review and the recovery of the costs is no longer subject to refund. In 2016, an additional $123 million of net regulatory liabilities will be amortized to income.

(e)

For transmission service provided pursuant to the open access transmission tariff of PJM Interconnection LLC (PJM), unless and until changed by the NYSPSC, the company will recover all charges incurred associated with the transmission service. In January 2014, PJM submitted to the FERC a request that would substantially increase the charges for the transmission service. FERC has granted the request and rejected CECONY’s protests. CECONY is challenging the FERC’s decision. In August 2015, PJM submitted a request to FERC that, if approved by FERC, would further increase the charges. In January 2016, FERC held a technical conference on this matter. It is anticipated that FERC will issue an order addressing this matter in 2016.

(f)

Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity. In general, if actual expenses for municipal infrastructure support (other than company labor) are below the amounts reflected in rates the company will defer the difference for credit to customers, and if the actual expenses are above the amount reflected in rates the company will defer for recovery from customers 80 percent of the difference subject to a maximum deferral of 30 percent of the amount reflected in rates.

In January 2016, CECONY filed a request with the NYSPSC for an electric rate increase of $482 million, effective January 2017. The filing reflects a return on common equity of 9.75 percent and a common equity ratio of 48 percent.

The company is requesting provisions pursuant to which expenses for pension and other postretirement benefits, variable-rate, tax-exempt long-term debt, storms, property taxes and municipal infrastructure support, the impact of new laws and environmental site investigation and remediation are reconciled to amounts reflected in rates. In addition, the company is requesting, among other things, full reconciliation for Reforming the Energy Vision (REV) distributed system implementation plan enablement costs and REV demonstration project costs. The filing also reflects continuation of the revenue decoupling mechanism and the provisions pursuant to which the company recovers its purchased power and fuel costs from customers.

The filing includes supplemental information regarding electric rate plans for 2018 and 2019, which the company is not requesting but would consider through settlement discussions. For purposes of illustration, rate increases of $180 million and $141 million effective January 2018 and 2019, respectively, were calculated based upon an assumed return on common equity of 9.75 percent and a common equity ratio of 48 percent.



CECONY – Gas
Effective period	October 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $47 million Yr. 2 – $48 million Yr. 3 – $47 million	Yr. 1 – $(54.6) million (b) Yr. 2 – $38.6 million (b) Yr. 3 – $56.8 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$(53.1) million over three years	$4 million over three years
Other revenue sources	Retention of revenues from non-firm customers of up to $58 million and 25 percent of any such revenues above $58 million. The company retained $57 million and $64 million of such revenues in 2012 and 2013, respectively.	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million and $66 million of such revenues in 2014 and 2015, respectively.
Revenue decoupling mechanisms	In 2012 and 2013, the company deferred $22 million and $36 million of regulatory liabilities, respectively.	In 2014 and 2015, the company deferred $28 million and $54 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $12.6 million annually) if certain gas performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014 and 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (c)	In 2012 and 2013, the company deferred $9 million and $26 million of net regulatory assets, respectively.	In 2014 and 2015, the company deferred $38 million and $11 million of net regulatory liabilities, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $2,934 million; Yr. 2 – $3,148 million; Yr. 3 – $3,346 million For 2012 and 2013, $2.9 million and $9.5 million were deferred as a regulatory liability respectively.	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million There were no deferrals recorded in 2014. In 2015, $1 million was deferred as a regulatory liability.
Average rate base	Yr. 1 – $3,027 million Yr. 2 – $3,245 million Yr. 3 – $3,434 million	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million
Weighted average cost of capital (after-tax)	7.46 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity	9.6 percent assuming the company achieved unspecified austerity measures of $4 million and $2 million in 2012 and 2013. Austerity measures were achieved.	9.3 percent
Earnings sharing	Actual earnings did not exceed the thresholds of 10.35 percent in Yr. 1 and 10.15 percent in Yrs. 2 and 3.	Most earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014 and 2015, the company had no earnings above the threshold.
Cost of long-term debt	5.57 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio	48 percent	48 percent


(a)	$32 million of annual revenues collected from gas customers is subject to potential refund. See “Other Regulatory Matters” below.


(b)	The impact of these base rate changes is being deferred which will result in a $32 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.

In January 2016, CECONY filed a request with the NYSPSC for a gas rate increase of $154 million, effective January 2017. The filing reflects a return on common equity of 9.75 percent and a common equity ratio of 48 percent.

The company is requesting provisions pursuant to which expenses for pension and other postretirement benefits, variable-rate, tax-exempt long-term debt, property taxes and municipal infrastructure support, the impact of new laws and environmental site investigation and remediation are reconciled to amounts reflected in rates. In addition, the company is, among other things, requesting full reconciliation for operations and maintenance costs associated with service line definition changes and proposing a reliability surcharge mechanism to recover costs associated with additional miles of main replacement above the annual targets. The filing also reflects continuation of the revenue decoupling mechanism and provisions pursuant to which the company recovers its purchased gas costs from customers.

The filing includes supplemental information regarding gas rate plans for 2018 and 2019, which the company is not requesting but would consider through settlement discussions. For purposes of illustration, rate increases of $97 million and $109 million effective January 2018 and 2019, respectively, were calculated based upon an assumed return on common equity of 9.75 percent and a common equity ratio of 48 percent.



CECONY – Steam
Effective period	October 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $49.5 million Yr. 2 – $49.5 million Yr. 3 – $17.8 million Yr. 3 – $31.7 million collected through a surcharge	Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$(20.1) million over three years	$37 million over three years
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014 and 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (c)	In 2012 and 2013, the company deferred $12 million and $17 million of net regulatory liabilities, respectively.	In 2014 and 2015, the company deferred $42 million and $17 million of net regulatory liabilities and assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Production: Yr. 1 – $415 million; Yr. 2 – $426 million; Yr. 3 – $433 million Distribution: Yr. 1 – $521 million; Yr. 2 – $534 million; Yr. 3 – $543 million The company reduced its regulatory liability by $0.2 million in 2012 and made no deferral in 2013.	Target levels reflected in rates were: Production: Yr. 1 – $1,752 million; Yr. 2 – $1,732 million; Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million; Yr. 2 – $11 million; Yr. 3 – $25 million The company reduced its regulatory liability by $1.1 million and an immaterial amount in 2014 and 2015, respectively.
Average rate base	Yr. 1 – $1,589 million Yr. 2 – $1,603 million Yr. 3 – $1,613 million	Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)	7.46 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity	9.6 percent (assuming company achieved unspecified austerity measures of $3 million and $2 million in 2012 and 2013). Austerity measures were achieved.	9.3 percent
Earnings sharing	Weather normalized earnings did not exceed the threshold of 10.35 percent in Yr. 1 and 10.15 percent in Yrs. 2 and 3. In 2013, actual earnings were $0.5 million above the earnings threshold of 10.15 percent.	Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $17.1 million above the threshold for 2015.
Cost of long-term debt	5.57 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio	48 percent	48 percent


(a)	$6 million of annual revenues collected from steam customers is subject to potential refund. See “Other Regulatory Matters” below.


(b)	The impact of these base rate changes is being deferred which will result in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.



O&R New York – Electric
Effective period	July 2012 – June 2015	November 2015 - October 2017
Base rate changes	Yr. 1 – $19.4 million Yr. 2 – $8.8 million Yr. 3 – $15.2 million	Yr. 1 – $9.3 million Yr. 2 – $8.8 million
Amortizations to income of net regulatory (assets) and liabilities	$(32.2) million over three years	Yr. 1 – $(8.5) million (a) Yr. 2 – $(9.4) million (a)
Revenue decoupling mechanisms	In 2012, 2013 and 2014, the company deferred for the customer’s benefit $2.6 million, $3.2 million and $(3.4) million.	In 2015, the company's deferral for the customer’s benefit was immaterial.
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power costs.
Negative revenue adjustments	Potential penalties (up to $3 million annually) if certain customer service and system reliability performance targets are not met. In 2012, 2013 and 2014, the company did not record any negative revenue adjustments.	Potential penalties (up to $4 million annually) if certain performance targets are not met. In 2015, the company recorded $1.25 million in negative revenue adjustments.
Cost reconciliations	In 2012, 2013 and 2014, the company deferred $7.8 million, $4.1 million and $(0.2) million as a net increase to regulatory assets, respectively.	In 2015, the company deferred $1.2 million as a net increase to regulatory assets.
Net utility plant reconciliations	Target levels reflected in rates were: Yr. 1 – $678 million; Yr. 2- $704 million; Yr. 3 – $753 million The company increased its regulatory liability by $4.2 million in 2012. The company reduced its regulatory liability by $1.1 million and $2.3 million in 2013 and 2014, respectively.	Target levels reflected in rates are: Yr. 1 – $928 million (b) Yr. 2 – $970 million (b) The company increased its regulatory asset by $2.2 million in 2015.
Average rate base	Yr. 1 – $671 million Yr. 2 – $708 million Yr. 3 – $759 million	Yr. 1 – $763 million Yr. 2 – $805 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.61 percent Yr. 2 – 7.65 percent Yr. 3 – 7.48 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent
Authorized return on common equity	Yr. 1 – 9.4 percent Yr. 2 – 9.5 percent Yr. 3 – 9.6 percent	9.0 percent
Earnings sharing	The company recorded a regulatory liability of $1 million for earnings above the sharing threshold under the rate plan as of December 31, 2014.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 6.07 percent Yr. 2 – 6.07 percent Yr. 3 – 5.64 percent	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent
Common equity ratio	48 percent	48 percent

(a)

$59.3 million of the regulatory asset for deferred storm costs is to be recovered from customers over a five years period, including $11.85 million in each of years 1 and 2, $1 million of the regulatory asset for such costs will not be recovered from customers, and all outstanding issues related to Superstorm Sandy and other past major storms prior to November 2014 are resolved. Approximately $4 million of regulatory assets for property tax and interest rate reconciliations will not be recovered from customers. Amounts that will not be recovered from customers were charged-off in June 2015.


(b)	Excludes electric advanced metering infrastructure as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.



O&R New York – Gas
Effective period	November 2009 – December 2014	November 2015 – October 2018
Base rate changes	Yr. 1 – $9 million Yr. 2 – $9 million Yr. 3 – $4.6 million Yr. 3 – $4.3 million collected through a surcharge	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge
Amortization to income of net regulatory (assets) and liabilities	$(2) million over three years	Yr. 1 – $(1.7) million (a) Yr. 2 – $(2.1) million (a) Yr. 3 – $(2.5) million (a)
Revenue decoupling mechanisms	In 2012, 2013 and 2014, the company deferred $4.7 million, $0.7 million and $(0.1) million of regulatory liabilities, respectively.	In 2015, the company deferred $0.8 million of regulatory assets.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $1.4 million annually) if certain operations and customer service requirements are not met. In 2012, 2013 and 2014, the company did not record any negative revenue adjustments.	Potential penalties (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $5.8 million in Yr. 3) if certain performance targets are not met. In 2015, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2012, 2013 and 2014, the company deferred $0.7 million, $8.3 million and $8.3 million as net regulatory assets, respectively.	In 2015, the company deferred $2.5 million as net regulatory assets.
Net utility plant reconciliations	The company deferred $0.7 million in 2012 as a regulatory asset and no deferrals were recorded for 2013 or 2014.	Target levels reflected in rates are: Yr. 1 – $492 million (b) Yr. 2 – $518 million (b) Yr. 3 – $546 million (b) The company recorded no deferrals in 2015.
Average rate base	Yr. 1 – $280 million Yr. 2 – $296 million Yr. 3 – $309 million	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million
Weighted average cost of capital (after-tax)	8.49 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent
Authorized return on common equity	10.4 percent	9.0 percent
Earnings sharing	Earnings above an annual earnings threshold of 11.4 percent are to be applied to reduce regulatory assets. In 2012, 2013 and 2014, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold.
Cost of long-term debt	6.81 percent	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent
Common equity ratio	48 percent	48 percent


(a)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(b)	Excludes gas advanced metering infrastructure as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.



Rockland Electric Company (RECO)
Effective period	May 2010 – July 2014	August 2014 – July 2015 (a)
Base rate changes	Yr. 1 – $9.8 million	Yr. 1 – $13.0 million
Amortization to income of net regulatory (assets) and liabilities	$(3.9) million over four years and $(4.9) million of deferred storm costs over five years	$0.4 million over three years and $(25.6) million of deferred storm costs over four years
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$148.6 million	$172.2 million
Weighted average cost of capital (after-tax)	8.21 percent	7.83 percent
Authorized return on common equity	10.3 percent	9.75 percent
Cost of long-term debt	6.16 percent	5.89 percent
Common equity ratio	50 percent	50 percent


(a)	In January 2016, the NJBPU approved RECO’s plan for a 3-year, $15.7 million electric system storm hardening capital program, the costs of which RECO will, beginning in 2017, collect through a customer surcharge until a new rate plan is approved that reflects the costs.



Pike – Electric
Effective period	April 2009 – August 2014	September 2014 – August 2015
Base rate changes(a)	Yr. 1 – $0.9 million	Yr. 1 – $1.25 million
Amortization to income of net regulatory (assets) and liabilities	$0.1 million over five years	$(0.7) million of deferred storm costs over five years
Cost reconciliations	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as regulatory liabilities in 2012 and 2013.	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as a regulatory liability in 2014 and 2015.


(a)	Under the current plan, the earliest that the company can file for a new base rate change is September 1, 2016.



Pike – Gas
Effective period	April 2009 – August 2014	September 2014 – August 2015
Base Rate changes(a)	Yr. 1 – $0.3 million	Yr. 1 – $0.1 million
Amortization to income of net regulatory (assets) and liabilities	None	None
Cost reconciliations	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as regulatory liabilities in 2012 and 2013.	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as a regulatory liability in 2014 and 2015.


(a)	Under the current plan, the earliest that the company can file for a new base rate change is September 1, 2016.

Other Regulatory Matters

In February 2009, the NYSPSC commenced a proceeding to examine the prudence of certain CECONY expenditures following the arrests of employees for accepting illegal payments from a construction contractor. Subsequently, additional employees were arrested for accepting illegal payments from materials suppliers and an engineering firm. The arrested employees were terminated by the company and have pled guilty or been convicted. Pursuant to NYSPSC orders, a portion of the company’s revenues (currently, $249 million, $32 million and $6 million on an annual basis for electric, gas and steam service, respectively) is being collected subject to potential refund to customers. The amount of electric revenues collected subject to refund, which was established in a different proceeding, and the amount of gas and steam revenues collected subject to refund were not established as indicative of the company’s potential liability in this proceeding. At December 31, 2015, the company had collected an estimated $1,962 million from customers subject to potential refund in connection with this proceeding. In January 2013, a NYSPSC consultant reported its estimate, with which the company does not agree, of $208 million of overcharges with respect to a substantial portion of the company’s construction expenditures from January 2000 to January 2009. The company disputed the consultant’s estimate, including its determinations as to overcharges regarding specific construction expenditures it selected to review and its methodology of extrapolating such determinations over a substantial portion of the construction expenditures during this period. The NYSPSC’s consultant has not reviewed the company’s other expenditures. In September 2015, the company, the NYSPSC staff and others entered into a Joint Proposal to settle this proceeding and related matters. The Joint Proposal is subject to NYSPSC approval. Pursuant to the Joint Proposal, the company is required to credit $116 million to customers and, for the period 2017 through 2044, to not seek to recover from customers an aggregate $55 million relating to return on its capital expenditures. In addition, the company’s revenues that were made subject to potential refund in this proceeding would no longer be subject to refund. At December 31, 2015, the company had a $99 million regulatory liability for the remaining amount to be credited to customers related to this matter.

In June 2014, the NYSPSC initiated a proceeding to investigate the practices of qualifying persons to perform plastic fusions on gas facilities. New York State regulations require gas utilities to qualify and, except in certain circumstances, annually requalify workers that perform fusion to join plastic pipe. The NYSPSC directed the New York gas utilities to provide information in this proceeding about their compliance with the qualification and requalification requirements and related matters; their procedures for compliance with all gas safety regulations; and their annual chief executive officer certifications regarding these and other procedures. CECONY’s qualification and requalification procedures had not included certain required testing to evaluate specimen fuses. In addition, CECONY and O&R had not timely requalified certain workers that had been qualified under their respective procedures to perform fusion to join plastic pipe. CECONY and O&R have requalified their workers who perform plastic pipe fusions. In May 2015, the NYSPSC, which indicated that it would address enforcement at a later date, ordered CECONY, O&R and other gas utilities to perform risk assessment and remediation plans, additional leakage surveying and reporting; CECONY to hire an independent statistician to develop a risk assessment and remediation plan; and the gas utilities to implement certain new plastic fusion requirements. In December 2015, the NYSPSC staff informed O&R that the company had satisfactorily completed its risk assessment and remediation plan. CECONY expects to submit its risk assessment and remediation plan to the NYSPSC staff in 2016. The Companies are unable to estimate the amount or range of their possible loss related to this proceeding.

In November 2015, the NYSPSC ordered CECONY to show cause why the NYSPSC should not commence proceedings to penalize the company for alleged violations of gas safety regulations identified by the NYSPSC staff in its investigation of a March 2014 explosion and fire and to review the prudence of the company’s conduct associated with the incident. See “Manhattan Explosion and Fire” in Note H. In December 2015, the company responded that the NYSPSC should not institute the proceedings and disputed the alleged violations. The company is unable to estimate the amount or range of its possible loss related to any such proceedings that may be instituted.

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2015 and 2014 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Regulatory assets
Unrecognized pension and other postretirement costs	$3,876	$4,846	$3,697	$4,609
Future income tax	2,350	2,259	2,232	2,142
Environmental remediation costs	904	925	800	820
Revenue taxes	253	219	240	208
Deferred storm costs	185	319	110	224
Unamortized loss on reacquired debt	50	57	48	55
Deferred derivative losses	50	25	46	23
O&R property tax reconciliation	46	36	—	—
Pension and other postretirement benefits deferrals	45	66	16	42
Surcharge for New York State assessment	44	99	40	92
Net electric deferrals	44	63	44	63
Preferred stock redemption	26	27	26	27
O&R transition bond charges	21	27	—	—
Recoverable energy costs	16	19	15	17
Workers’ compensation	11	8	11	8
Other	175	147	157	127
Regulatory assets – noncurrent	8,096	9,142	7,482	8,457
Deferred derivative losses	113	97	103	92
Recoverable energy costs	19	41	18	40
Regulatory assets – current	132	138	121	132
Total Regulatory Assets	$8,228	$9,280	$7,603	$8,589
Regulatory liabilities
Allowance for cost of removal less salvage	$676	$598	$570	$499
Property tax reconciliation	303	295	303	295
Base rate change deferrals	128	155	128	155
Net unbilled revenue deferrals	109	138	109	138
Prudence proceeding	99	105	99	105
Earnings sharing - electric and steam	80	19	80	18
Pension and other postretirement benefit deferrals	76	46	46	37
New York State income tax rate change	75	62	72	59
Variable-rate tax-exempt debt - cost rate reconciliation	70	78	60	78
Carrying charges on repair allowance and bonus depreciation	49	58	48	57
Property tax refunds	44	87	44	87
Net utility plant reconciliations	32	21	31	20
Unrecognized other postretirement costs	28	—	28	—
World Trade Center settlement proceeds	21	41	21	41
Other	187	290	150	248
Regulatory liabilities – noncurrent	1,977	1,993	1,789	1,837
Refundable energy costs	64	128	33	84
Revenue decoupling mechanism	45	30	45	30
Deferred derivative gains	6	5	6	4
Regulatory liabilities—current	115	163	84	118
Total Regulatory Liabilities	$2,092	$2,156	$1,873	$1,955

Unrecognized pension and other postretirement costs represents the net regulatory asset associated with the accounting rules for retirement benefits. See Note A.

Deferred storm costs represent response and restoration costs, other than capital expenditures, in connection with Superstorm Sandy and other major storms that were deferred by the Utilities.

Net electric deferrals represents the remaining unamortized balance of certain regulatory assets and liabilities of CECONY that were combined effective April 1, 2010 and are being amortized to income over a ten-year period.

Revenue taxes represents the timing difference between taxes collected and paid by the Utilities to fund mass transportation.

The NYSPSC has authorized CECONY to accrue unbilled electric, gas and steam revenues. CECONY has deferred the net margin on the unbilled revenues for the future benefit of customers by recording a regulatory liability of $109 million and $138 million at December 31, 2015 and 2014, respectively, for the difference between the unbilled revenues and energy cost liabilities.

CECONY

Regulatory Matters

Rate Plans

Common provisions of the Utilities’ rate plans include:

Recoverable energy costs that allow the Utilities to recover on a current basis the costs for the energy they supply with no mark-up to their full-service customers.

Negative revenue adjustments for failure to meet certain performance standards relating to service, reliability, safety and other matters.

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	April 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $420 million Yr. 2 – $420 million Yr. 3 – $287 million(b)	Yr. 1 – $(76.2) million (c) Yr. 2 – $124.0 million (c) Yr. 3 – None
Amortizations to income of net regulatory (assets) and liabilities	$(75.3) million over three years	Yr. 1 and 2 – $(37) million (d) Yr. 3 - $123 million (d)
Other revenue sources	Retention of $120 million of annual transmission congestion revenues from the sale of transmission rights ($90 million for the period April 1, 2013 to December 31, 2013).	Retention of $90 million of annual transmission congestion revenues.
Revenue decoupling mechanisms	In 2012 and 2013, the company deferred for customer benefit $59 million and $34 million of revenues, respectively.	In 2014 and 2015, the company deferred for customer benefit $146 million and $98 million of revenues, respectively.
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power and fuel costs (e).
Negative revenue adjustments	Potential penalties (up to $350 million annually) if certain performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (f)	In 2012 and 2013, the company deferred $146 million of net regulatory liabilities and $35 million of net regulatory assets, respectively.	In 2014 and 2015, the company deferred $57 million and $26 million of net regulatory liabilities, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $13,818 million Yr. 2 – $14,742 million Yr. 3 – $15,414 million Enterprise resource project: Yr. 2 – $25 million; Yr. 3 -$115 million; Other: Yr. 1 – $1,487 million; Yr. 2 – $1,565 million; Yr. 3 – $1,650 million The company deferred an immaterial amount and $7 million as a regulatory liability in 2012 and 2013, respectively.	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred an immaterial amount and $17 million as a regulatory liability in 2014 and 2015, respectively.
Average rate base	Yr. 1 – $14,887 million Yr. 2 – $15,987 million Yr. 3 – $16,826 million	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million
Weighted average cost of capital (after-tax)	7.76 percent	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent
Authorized return on common equity	10.15 percent assuming the company achieved austerity measures of $27 million, $20 million and $13 million for Yrs. 1, 2 and 3, respectively. Austerity measures were achieved.	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent
Earnings sharing	Actual earnings above an annual earnings threshold of 11.15 percent for Yr. 1 and 10.65 percent for Yrs. 2 and 3 were to be applied to reduce regulatory assets for pensions and other postretirement benefits and other costs. Actual earnings were $17.5 million above the threshold for the period ended 2013.	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $44.4 million above the threshold for 2015.
Cost of long-term debt	5.65 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent
Common equity ratio	48 percent	48 percent


(a)	$249 million of annual revenues collected from electric customers will continue to be subject to potential refund following NYSPSC staff review of certain costs. See "Other Regulatory Matters" below. Revenues for 2014 through 2016 will include $21 million as funding for major storm reserve.


(b)	Temporary portion of the increase ($134 million) that was scheduled to go into effect April 1, 2012 was eliminated by the application of available credits.


(c)	The impact of these base rate changes were deferred which resulted in a $30 million regulatory liability at December 31, 2015.

(d)

(e)

(f)



CECONY – Gas
Effective period	October 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $47 million Yr. 2 – $48 million Yr. 3 – $47 million	Yr. 1 – $(54.6) million (b) Yr. 2 – $38.6 million (b) Yr. 3 – $56.8 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$(53.1) million over three years	$4 million over three years
Other revenue sources	Retention of revenues from non-firm customers of up to $58 million and 25 percent of any such revenues above $58 million. The company retained $57 million and $64 million of such revenues in 2012 and 2013, respectively.	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million and $66 million of such revenues in 2014 and 2015, respectively.
Revenue decoupling mechanisms	In 2012 and 2013, the company deferred $22 million and $36 million of regulatory liabilities, respectively.	In 2014 and 2015, the company deferred $28 million and $54 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $12.6 million annually) if certain gas performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014 and 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (c)	In 2012 and 2013, the company deferred $9 million and $26 million of net regulatory assets, respectively.	In 2014 and 2015, the company deferred $38 million and $11 million of net regulatory liabilities, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $2,934 million; Yr. 2 – $3,148 million; Yr. 3 – $3,346 million For 2012 and 2013, $2.9 million and $9.5 million were deferred as a regulatory liability respectively.	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million There were no deferrals recorded in 2014. In 2015, $1 million was deferred as a regulatory liability.
Average rate base	Yr. 1 – $3,027 million Yr. 2 – $3,245 million Yr. 3 – $3,434 million	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million
Weighted average cost of capital (after-tax)	7.46 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity	9.6 percent assuming the company achieved unspecified austerity measures of $4 million and $2 million in 2012 and 2013. Austerity measures were achieved.	9.3 percent
Earnings sharing	Actual earnings did not exceed the thresholds of 10.35 percent in Yr. 1 and 10.15 percent in Yrs. 2 and 3.	Most earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014 and 2015, the company had no earnings above the threshold.
Cost of long-term debt	5.57 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio	48 percent	48 percent


(a)	$32 million of annual revenues collected from gas customers is subject to potential refund. See “Other Regulatory Matters” below.


(b)	The impact of these base rate changes is being deferred which will result in a $32 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.



CECONY – Steam
Effective period	October 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $49.5 million Yr. 2 – $49.5 million Yr. 3 – $17.8 million Yr. 3 – $31.7 million collected through a surcharge	Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$(20.1) million over three years	$37 million over three years
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014 and 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (c)	In 2012 and 2013, the company deferred $12 million and $17 million of net regulatory liabilities, respectively.	In 2014 and 2015, the company deferred $42 million and $17 million of net regulatory liabilities and assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Production: Yr. 1 – $415 million; Yr. 2 – $426 million; Yr. 3 – $433 million Distribution: Yr. 1 – $521 million; Yr. 2 – $534 million; Yr. 3 – $543 million The company reduced its regulatory liability by $0.2 million in 2012 and made no deferral in 2013.	Target levels reflected in rates were: Production: Yr. 1 – $1,752 million; Yr. 2 – $1,732 million; Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million; Yr. 2 – $11 million; Yr. 3 – $25 million The company reduced its regulatory liability by $1.1 million and an immaterial amount in 2014 and 2015, respectively.
Average rate base	Yr. 1 – $1,589 million Yr. 2 – $1,603 million Yr. 3 – $1,613 million	Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)	7.46 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity	9.6 percent (assuming company achieved unspecified austerity measures of $3 million and $2 million in 2012 and 2013). Austerity measures were achieved.	9.3 percent
Earnings sharing	Weather normalized earnings did not exceed the threshold of 10.35 percent in Yr. 1 and 10.15 percent in Yrs. 2 and 3. In 2013, actual earnings were $0.5 million above the earnings threshold of 10.15 percent.	Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $17.1 million above the threshold for 2015.
Cost of long-term debt	5.57 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio	48 percent	48 percent


(a)	$6 million of annual revenues collected from steam customers is subject to potential refund. See “Other Regulatory Matters” below.


(b)	The impact of these base rate changes is being deferred which will result in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.



O&R New York – Electric
Effective period	July 2012 – June 2015	November 2015 - October 2017
Base rate changes	Yr. 1 – $19.4 million Yr. 2 – $8.8 million Yr. 3 – $15.2 million	Yr. 1 – $9.3 million Yr. 2 – $8.8 million
Amortizations to income of net regulatory (assets) and liabilities	$(32.2) million over three years	Yr. 1 – $(8.5) million (a) Yr. 2 – $(9.4) million (a)
Revenue decoupling mechanisms	In 2012, 2013 and 2014, the company deferred for the customer’s benefit $2.6 million, $3.2 million and $(3.4) million.	In 2015, the company's deferral for the customer’s benefit was immaterial.
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power costs.
Negative revenue adjustments	Potential penalties (up to $3 million annually) if certain customer service and system reliability performance targets are not met. In 2012, 2013 and 2014, the company did not record any negative revenue adjustments.	Potential penalties (up to $4 million annually) if certain performance targets are not met. In 2015, the company recorded $1.25 million in negative revenue adjustments.
Cost reconciliations	In 2012, 2013 and 2014, the company deferred $7.8 million, $4.1 million and $(0.2) million as a net increase to regulatory assets, respectively.	In 2015, the company deferred $1.2 million as a net increase to regulatory assets.
Net utility plant reconciliations	Target levels reflected in rates were: Yr. 1 – $678 million; Yr. 2- $704 million; Yr. 3 – $753 million The company increased its regulatory liability by $4.2 million in 2012. The company reduced its regulatory liability by $1.1 million and $2.3 million in 2013 and 2014, respectively.	Target levels reflected in rates are: Yr. 1 – $928 million (b) Yr. 2 – $970 million (b) The company increased its regulatory asset by $2.2 million in 2015.
Average rate base	Yr. 1 – $671 million Yr. 2 – $708 million Yr. 3 – $759 million	Yr. 1 – $763 million Yr. 2 – $805 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.61 percent Yr. 2 – 7.65 percent Yr. 3 – 7.48 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent
Authorized return on common equity	Yr. 1 – 9.4 percent Yr. 2 – 9.5 percent Yr. 3 – 9.6 percent	9.0 percent
Earnings sharing	The company recorded a regulatory liability of $1 million for earnings above the sharing threshold under the rate plan as of December 31, 2014.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 6.07 percent Yr. 2 – 6.07 percent Yr. 3 – 5.64 percent	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent
Common equity ratio	48 percent	48 percent

(a)


(b)	Excludes electric advanced metering infrastructure as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.



O&R New York – Gas
Effective period	November 2009 – December 2014	November 2015 – October 2018
Base rate changes	Yr. 1 – $9 million Yr. 2 – $9 million Yr. 3 – $4.6 million Yr. 3 – $4.3 million collected through a surcharge	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge
Amortization to income of net regulatory (assets) and liabilities	$(2) million over three years	Yr. 1 – $(1.7) million (a) Yr. 2 – $(2.1) million (a) Yr. 3 – $(2.5) million (a)
Revenue decoupling mechanisms	In 2012, 2013 and 2014, the company deferred $4.7 million, $0.7 million and $(0.1) million of regulatory liabilities, respectively.	In 2015, the company deferred $0.8 million of regulatory assets.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $1.4 million annually) if certain operations and customer service requirements are not met. In 2012, 2013 and 2014, the company did not record any negative revenue adjustments.	Potential penalties (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $5.8 million in Yr. 3) if certain performance targets are not met. In 2015, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2012, 2013 and 2014, the company deferred $0.7 million, $8.3 million and $8.3 million as net regulatory assets, respectively.	In 2015, the company deferred $2.5 million as net regulatory assets.
Net utility plant reconciliations	The company deferred $0.7 million in 2012 as a regulatory asset and no deferrals were recorded for 2013 or 2014.	Target levels reflected in rates are: Yr. 1 – $492 million (b) Yr. 2 – $518 million (b) Yr. 3 – $546 million (b) The company recorded no deferrals in 2015.
Average rate base	Yr. 1 – $280 million Yr. 2 – $296 million Yr. 3 – $309 million	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million
Weighted average cost of capital (after-tax)	8.49 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent
Authorized return on common equity	10.4 percent	9.0 percent
Earnings sharing	Earnings above an annual earnings threshold of 11.4 percent are to be applied to reduce regulatory assets. In 2012, 2013 and 2014, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold.
Cost of long-term debt	6.81 percent	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent
Common equity ratio	48 percent	48 percent


(a)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(b)	Excludes gas advanced metering infrastructure as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.



Rockland Electric Company (RECO)
Effective period	May 2010 – July 2014	August 2014 – July 2015 (a)
Base rate changes	Yr. 1 – $9.8 million	Yr. 1 – $13.0 million
Amortization to income of net regulatory (assets) and liabilities	$(3.9) million over four years and $(4.9) million of deferred storm costs over five years	$0.4 million over three years and $(25.6) million of deferred storm costs over four years
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$148.6 million	$172.2 million
Weighted average cost of capital (after-tax)	8.21 percent	7.83 percent
Authorized return on common equity	10.3 percent	9.75 percent
Cost of long-term debt	6.16 percent	5.89 percent
Common equity ratio	50 percent	50 percent


(a)	In January 2016, the NJBPU approved RECO’s plan for a 3-year, $15.7 million electric system storm hardening capital program, the costs of which RECO will, beginning in 2017, collect through a customer surcharge until a new rate plan is approved that reflects the costs.



Pike – Electric
Effective period	April 2009 – August 2014	September 2014 – August 2015
Base rate changes(a)	Yr. 1 – $0.9 million	Yr. 1 – $1.25 million
Amortization to income of net regulatory (assets) and liabilities	$0.1 million over five years	$(0.7) million of deferred storm costs over five years
Cost reconciliations	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as regulatory liabilities in 2012 and 2013.	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as a regulatory liability in 2014 and 2015.


(a)	Under the current plan, the earliest that the company can file for a new base rate change is September 1, 2016.



Pike – Gas
Effective period	April 2009 – August 2014	September 2014 – August 2015
Base Rate changes(a)	Yr. 1 – $0.3 million	Yr. 1 – $0.1 million
Amortization to income of net regulatory (assets) and liabilities	None	None
Cost reconciliations	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as regulatory liabilities in 2012 and 2013.	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as a regulatory liability in 2014 and 2015.


(a)	Under the current plan, the earliest that the company can file for a new base rate change is September 1, 2016.

Other Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2015 and 2014 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Regulatory assets
Unrecognized pension and other postretirement costs	$3,876	$4,846	$3,697	$4,609
Future income tax	2,350	2,259	2,232	2,142
Environmental remediation costs	904	925	800	820
Revenue taxes	253	219	240	208
Deferred storm costs	185	319	110	224
Unamortized loss on reacquired debt	50	57	48	55
Deferred derivative losses	50	25	46	23
O&R property tax reconciliation	46	36	—	—
Pension and other postretirement benefits deferrals	45	66	16	42
Surcharge for New York State assessment	44	99	40	92
Net electric deferrals	44	63	44	63
Preferred stock redemption	26	27	26	27
O&R transition bond charges	21	27	—	—
Recoverable energy costs	16	19	15	17
Workers’ compensation	11	8	11	8
Other	175	147	157	127
Regulatory assets – noncurrent	8,096	9,142	7,482	8,457
Deferred derivative losses	113	97	103	92
Recoverable energy costs	19	41	18	40
Regulatory assets – current	132	138	121	132
Total Regulatory Assets	$8,228	$9,280	$7,603	$8,589
Regulatory liabilities
Allowance for cost of removal less salvage	$676	$598	$570	$499
Property tax reconciliation	303	295	303	295
Base rate change deferrals	128	155	128	155
Net unbilled revenue deferrals	109	138	109	138
Prudence proceeding	99	105	99	105
Earnings sharing - electric and steam	80	19	80	18
Pension and other postretirement benefit deferrals	76	46	46	37
New York State income tax rate change	75	62	72	59
Variable-rate tax-exempt debt - cost rate reconciliation	70	78	60	78
Carrying charges on repair allowance and bonus depreciation	49	58	48	57
Property tax refunds	44	87	44	87
Net utility plant reconciliations	32	21	31	20
Unrecognized other postretirement costs	28	—	28	—
World Trade Center settlement proceeds	21	41	21	41
Other	187	290	150	248
Regulatory liabilities – noncurrent	1,977	1,993	1,789	1,837
Refundable energy costs	64	128	33	84
Revenue decoupling mechanism	45	30	45	30
Deferred derivative gains	6	5	6	4
Regulatory liabilities—current	115	163	84	118
Total Regulatory Liabilities	$2,092	$2,156	$1,873	$1,955

Unrecognized pension and other postretirement costs represents the net regulatory asset associated with the accounting rules for retirement benefits. See Note A.

Deferred storm costs represent response and restoration costs, other than capital expenditures, in connection with Superstorm Sandy and other major storms that were deferred by the Utilities.

Revenue taxes represents the timing difference between taxes collected and paid by the Utilities to fund mass transportation.

Capitalization

12 Months Ended

Dec. 31, 2015

Schedule of Capitalization [Line Items]

Capitalization

Common Stock

At December 31, 2015 and 2014, Con Edison owned all of the issued and outstanding shares of common stock of the Utilities, the competitive energy businesses and Con Edison Transmission. CECONY owns 21,976,200 shares of Con Edison stock, which it purchased prior to 2001 in connection with Con Edison’s stock repurchase plan. CECONY presents in the financial statements the cost of the Con Edison stock it owns as a reduction of common shareholder’s equity.

Capitalization of Con Edison

The outstanding capitalization for each of the Companies is shown on its Consolidated Statement of Capitalization, and for Con Edison includes the Utilities’ outstanding debt.

Dividends

In accordance with NYSPSC requirements, the dividends that the Utilities generally pay are limited to not more than 100 percent of their respective income available for dividends calculated on a two-year rolling average basis. Excluded from the calculation of “income available for dividends” are non-cash charges to income resulting from accounting changes or charges to income resulting from significant unanticipated events. The restriction also does not apply to dividends paid in order to transfer to Con Edison proceeds from major transactions, such as asset sales, or to dividends reducing each utility subsidiary’s equity ratio to a level appropriate to its business risk.

Long-term Debt

Long-term debt maturing in the period 2016-2020 is as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$739	$650
2017	16	—
2018	1,266	1,200
2019	552	475
2020	365	350

CECONY has issued $450 million of tax-exempt debt through the New York State Energy Research and Development Authority (NYSERDA) that currently bear interest at a rate determined weekly and is subject to tender by bondholders for purchase by the company.

The carrying amounts and fair values of long-term debt at December 31, 2015 and 2014 are:



(Millions of Dollars)	2015		2014
Long-Term Debt (including current portion)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$12,745	$13,856	$12,106	$13,913
CECONY	$11,437	$12,427	$11,138	$12,770

Fair values of long-term debt have been estimated primarily using available market information. For Con Edison, $13,220 million and $636 million of the fair value of long-term debt at December 31, 2015 are classified as Level 2 and Level 3, respectively. For CECONY, $11,791 million and $636 million of the fair value of long-term debt at December 31, 2015 are classified as Level 2 and Level 3, respectively (see Note P). The $636 million of long-term debt classified as Level 3 is CECONY’s tax-exempt, auction-rate securities for which the market is highly illiquid and there is a lack of observable inputs.

At December 31, 2015 and 2014, long-term debt of Con Edison included $15 million and $18 million, respectively, of Transition Bonds issued in 2004 by O&R’s New Jersey utility subsidiary through a special purpose entity.

Unamortized Debt Issuance Costs

The Companies adopted Accounting Standards Update (ASU) No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” as of December 31, 2015, requiring that debt issuance costs be presented as a reduction to the carrying value of the related debt. In prior years, these costs were presented as other assets on the consolidated balance sheet. Prior year consolidated balance sheets have been adjusted retrospectively to conform with the current year presentation. With the adoption of the new pronouncement, unamortized debt issuance costs associated with outstanding long-term debt of $91 million and $85 million for Con Edison and $78 million and $76 million for CECONY as of December 31, 2015 and 2014, respectively, has been reclassified from other assets to a reduction of the carrying value of long-term debt.

Significant Debt Covenants

The significant debt covenants under the financing arrangements for the notes of Con Edison and the debentures of CECONY are obligations to pay principal and interest when due, covenants not to consolidate with or merge into any other corporation unless certain conditions are met and, for Con Edison’s notes, covenants that Con Edison shall continue its utility business in New York City and shall not permit Con Edison's ratio of consolidated debt to consolidated capital to exceed 0.675 to 1. Con Edison’s notes are also subject to cross default provisions with respect to other indebtedness of Con Edison or its material subsidiaries having a then outstanding principal balance in excess of $100 million. CECONY’s debentures have no cross default provisions. The tax-exempt financing arrangements of the Utilities are subject to covenants for the CECONY debentures discussed above and the covenants discussed below. The Companies were in compliance with their significant debt covenants at December 31, 2015.

The tax-exempt financing arrangements involved the issuance of uncollateralized promissory notes of the Utilities to NYSERDA in exchange for the net proceeds of a like amount of tax-exempt bonds with substantially the same terms sold to the public by NYSERDA. The tax-exempt financing arrangements include covenants with respect to the tax-exempt status of the financing, including covenants with respect to the use of the facilities financed. The arrangements include provisions for the maintenance of liquidity and credit facilities, the failure to comply with which would, except as otherwise provided, constitute an event of default for the debt to which such provisions applied.

The failure to comply with debt covenants would, except as otherwise provided, constitute an event of default for the debt to which such provisions applied. If an event of default were to occur, the principal and accrued interest on the debt to which such event of default applied and, in the case of the Con Edison notes, a make-whole premium might and, in the case of certain events of default would, become due and payable immediately.

The liquidity and credit facilities currently in effect for the tax-exempt financing include covenants that the ratio of debt to total capital of the obligated utility will not at any time exceed 0.65 to 1 and that, subject to certain exceptions, the utility will not mortgage, lien, pledge or otherwise encumber its assets. Certain of the facilities also include as events of default, defaults in payments of other debt obligations in excess of specified levels ($150 million or $100 million for CECONY, depending on the facility).

CECONY

Schedule of Capitalization [Line Items]

Capitalization

Common Stock

Capitalization of Con Edison

The outstanding capitalization for each of the Companies is shown on its Consolidated Statement of Capitalization, and for Con Edison includes the Utilities’ outstanding debt.

Dividends

Long-term Debt

Long-term debt maturing in the period 2016-2020 is as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$739	$650
2017	16	—
2018	1,266	1,200
2019	552	475
2020	365	350

The carrying amounts and fair values of long-term debt at December 31, 2015 and 2014 are:



(Millions of Dollars)	2015		2014
Long-Term Debt (including current portion)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$12,745	$13,856	$12,106	$13,913
CECONY	$11,437	$12,427	$11,138	$12,770

Unamortized Debt Issuance Costs

Significant Debt Covenants

Short-Term Borrowing	12 Months Ended
Short-Term Borrowing	Dec. 31, 2015
Short-term Debt [Line Items]
Short-Term Borrowing	Short-Term Borrowing In October 2011, Con Edison and the Utilities entered into a credit agreement (Credit Agreement), under which banks are committed to provide loans and letters of credit on a revolving credit basis. The Credit Agreement, as amended, expires in October 2017. There is a maximum of $2.25 billion of credit available through October 2016 and approximately $2.1 billion of credit available from then through October 2017. The full amount is available to CECONY and $1.5 billion is available to Con Edison, including up to $1.2 billion of letters of credit. The Credit Agreement supports the Companies’ commercial paper programs. The Companies have not borrowed under the Credit Agreement. At December 31, 2015, Con Edison had $1,529 million of commercial paper outstanding of which $1,033 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2015 was 0.7 percent for both Con Edison and CECONY. At December 31, 2014, Con Edison had $800 million of commercial paper outstanding of which $450 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2014 was 0.4 percent for both Con Edison and CECONY. At December 31, 2015 and 2014, no loans were outstanding under the Credit Agreement and $15 million and $11 million (including $11 million for CECONY) of letters of credit were outstanding under the Credit Agreement, respectively. The banks’ commitments under the Credit Agreement are subject to certain conditions, including that there be no event of default. The commitments are not subject to maintenance of credit rating levels or the absence of a material adverse change. Upon a change of control of, or upon an event of default by one of the Companies, the banks may terminate their commitments with respect to that company, declare any amounts owed by that company under the Credit Agreement immediately due and payable and require that company to provide cash collateral relating to the letters of credit issued for it under the Credit Agreement. Events of default include the exceeding at any time of a ratio of consolidated debt to consolidated total capital of 0.65 to 1 (at December 31, 2015 this ratio was 0.52 to 1 for Con Edison and CECONY); having liens on its assets in an aggregate amount exceeding five percent of its consolidated total capital, subject to certain exceptions; and the failure, following any applicable notice period, to meet certain other customary covenants. Interest and fees charged for the revolving credit facilities and any loans made or letters of credit issued under the Credit Agreement reflect the Companies’ respective credit ratings. The Companies were in compliance with their covenants at December 31, 2015. See Note S for information about short-term borrowing between related parties.
CECONY
Short-term Debt [Line Items]
Short-Term Borrowing	Short-Term Borrowing In October 2011, Con Edison and the Utilities entered into a credit agreement (Credit Agreement), under which banks are committed to provide loans and letters of credit on a revolving credit basis. The Credit Agreement, as amended, expires in October 2017. There is a maximum of $2.25 billion of credit available through October 2016 and approximately $2.1 billion of credit available from then through October 2017. The full amount is available to CECONY and $1.5 billion is available to Con Edison, including up to $1.2 billion of letters of credit. The Credit Agreement supports the Companies’ commercial paper programs. The Companies have not borrowed under the Credit Agreement. At December 31, 2015, Con Edison had $1,529 million of commercial paper outstanding of which $1,033 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2015 was 0.7 percent for both Con Edison and CECONY. At December 31, 2014, Con Edison had $800 million of commercial paper outstanding of which $450 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2014 was 0.4 percent for both Con Edison and CECONY. At December 31, 2015 and 2014, no loans were outstanding under the Credit Agreement and $15 million and $11 million (including $11 million for CECONY) of letters of credit were outstanding under the Credit Agreement, respectively. The banks’ commitments under the Credit Agreement are subject to certain conditions, including that there be no event of default. The commitments are not subject to maintenance of credit rating levels or the absence of a material adverse change. Upon a change of control of, or upon an event of default by one of the Companies, the banks may terminate their commitments with respect to that company, declare any amounts owed by that company under the Credit Agreement immediately due and payable and require that company to provide cash collateral relating to the letters of credit issued for it under the Credit Agreement. Events of default include the exceeding at any time of a ratio of consolidated debt to consolidated total capital of 0.65 to 1 (at December 31, 2015 this ratio was 0.52 to 1 for Con Edison and CECONY); having liens on its assets in an aggregate amount exceeding five percent of its consolidated total capital, subject to certain exceptions; and the failure, following any applicable notice period, to meet certain other customary covenants. Interest and fees charged for the revolving credit facilities and any loans made or letters of credit issued under the Credit Agreement reflect the Companies’ respective credit ratings. The Companies were in compliance with their covenants at December 31, 2015. See Note S for information about short-term borrowing between related parties.

Pension Benefits

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Pension Benefits

Con Edison maintains a tax-qualified, non-contributory pension plan that covers substantially all employees of CECONY and O&R and certain employees of Con Edison’s competitive energy businesses. The plan is designed to comply with the Internal Revenue Code and the Employee Retirement Income Security Act of 1974. In addition, Con Edison maintains additional non-qualified supplemental pension plans.

Total Periodic Benefit Cost

The components of the Companies’ total periodic benefit costs for 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Service cost – including administrative expenses	$297	$227	$267	$279	$211	$249
Interest cost on projected benefit obligation	575	572	537	538	536	503
Expected return on plan assets	(886)	(832)	(750)	(840)	(789)	(713)
Recognition of net actuarial loss	775	618	832	734	586	788
Recognition of prior service costs	4	4	5	2	2	4
NET PERIODIC BENEFIT COST	$765	$589	$891	$713	$546	$831
Amortization of regulatory asset (a)	1	2	2	1	2	2
TOTAL PERIODIC BENEFIT COST	$766	$591	$893	$714	$548	$833
Cost capitalized	(301)	(225)	(348)	(285)	(212)	(327)
Reconciliation to rate level	(74)	118	(84)	(74)	108	(87)
Cost charged to operating expenses	$391	$484	$461	$355	$444	$419

(a) Relates to an increase in CECONY’s pension obligation of $45 million from a 1999 special retirement program.

Funded Status

The funded status at December 31, 2015, 2014 and 2013 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$15,081	$12,197	$13,406	$14,137	$11,429	$12,572
Service cost – excluding administrative expenses	293	221	259	274	206	241
Interest cost on projected benefit obligation	575	572	537	538	536	503
Net actuarial (gain)/loss	(996)	2,641	(1,469)	(931)	2,484	(1,388)
Plan amendments	—	6	—	—	—	—
Benefits paid	(576)	(556)	(536)	(536)	(518)	(499)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$14,377	$15,081	$12,197	$13,482	$14,137	$11,429
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$11,495	$10,755	$9,135	$10,897	$10,197	$8,668
Actual return on plan assets	126	752	1,310	118	715	1,241
Employer contributions	750	578	879	697	535	819
Benefits paid	(576)	(556)	(536)	(536)	(518)	(499)
Administrative expenses	(36)	(34)	(33)	(35)	(32)	(32)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$11,759	$11,495	$10,755	$11,141	$10,897	$10,197
FUNDED STATUS	$(2,618)	$(3,586)	$(1,442)	$(2,341)	$(3,240)	$(1,232)
Unrecognized net loss	$3,909	$4,888	$2,759	$3,704	$4,616	$2,617
Unrecognized prior service costs	16	20	17	3	4	6
Accumulated benefit obligation	12,909	13,454	11,004	12,055	12,553	10,268

The decrease in the pension plan’s projected benefit obligation (due primarily to increased discount rates) was the primary cause of the decreased pension liability at Con Edison and CECONY of $968 million and $899 million, respectively, compared with December 31, 2014. For Con Edison, this decrease in pension liability corresponds with a decrease to regulatory assets of $967 million for unrecognized net losses and unrecognized prior service costs associated with the Utilities consistent with the accounting rules for regulated operations, a credit to OCI of $10 million (net of taxes) for the unrecognized net losses, and an immaterial change to OCI (net of taxes) for the unrecognized prior service costs associated with the competitive energy businesses and O&R’s New Jersey and Pennsylvania utility subsidiaries.

For CECONY, the decrease in pension liability corresponds with a decrease to regulatory assets of $911 million for unrecognized net losses and unrecognized prior service costs consistent with the accounting rules for regulated operations, a credit to OCI of $1 million (net of taxes) for unrecognized net losses, and an immaterial change to OCI (net of taxes) for the unrecognized prior service costs associated with the competitive energy businesses.

A portion of the unrecognized net loss and prior service cost for the pension plan, equal to $603 million and $4 million, respectively, will be recognized from accumulated OCI and the regulatory asset into net periodic benefit cost over the next year for Con Edison. Included in these amounts are $570 million and $2 million, respectively, for CECONY.

At December 31, 2015 and 2014, Con Edison’s investments include $243 million and $225 million, respectively, held in external trust accounts for benefit payments pursuant to the supplemental retirement plans. Included in these amounts for CECONY were $221 million and $208 million, respectively. See Note P. The accumulated benefit obligations for the supplemental retirement plans for Con Edison and CECONY were $285 million and $249 million as of December 31, 2015 and $289 million and $250 million as of December 31, 2014, respectively.

Assumptions

The actuarial assumptions were as follows:



	2015		2014		2013
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	4.25	%	3.90	%	4.80	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.35	%
O&R	4.00	%	4.00	%	4.25	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	3.90	%	4.80	%	4.10	%
Expected return on plan assets	7.80	%	8.00	%	8.00	%
Rate of compensation increase
CECONY	4.25	%	4.35	%	4.35	%
O&R	4.00	%	4.25	%	4.25	%

The expected return assumption reflects anticipated returns on the plan’s current and future assets. The Companies’ expected return was based on an evaluation of the current environment, market and economic outlook, relationships between the economy and asset class performance patterns, and recent and long-term trends in asset class performance. The projections were based on the plan’s target asset allocation.

Discount Rate Assumption

To determine the assumed discount rate, the Companies use a model that produces a yield curve based on yields on selected highly rated (Aa or higher by either Moody’s Investors Service (Moody’s) or Standard & Poor’s) corporate bonds. Bonds with insufficient liquidity, bonds with questionable pricing information and bonds that are not representative of the overall market are excluded from consideration. For example, the bonds used in the model cannot be callable, they must have a price between 50 percent and 200 percent of the original price, the yield must lie between 1 percent and 20 percent, and the amount of the bond issue outstanding must be in excess of $50 million. The spot rates defined by the yield curve and the plan’s projected benefit payments are used to develop a weighted average discount rate.

Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years:



(Millions of Dollars)	2016	2017	2018	2019	2020	2021-2025
Con Edison	$614	$636	$658	$680	$701	$3,800
CECONY	572	593	614	635	655	3,548

Expected Contributions

Based on estimates as of December 31, 2015, the Companies expect to make contributions to the pension plans during 2016 of $507 million (of which $469 million is to be contributed by CECONY). The Companies’ policy is to fund the total periodic benefit cost of the qualified plan to the extent tax deductible and to also contribute to the non-qualified supplemental plans.

Plan Assets

The asset allocations for the pension plan at the end of 2015, 2014 and 2013, and the target allocation for 2016 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2016	2015		2014		2013
Equity Securities	55% - 65%	57	%	58	%	60	%
Debt Securities	27% - 33%	33	%	32	%	30	%
Real Estate	8% - 12%	10	%	10	%	10	%
Total	100%	100	%	100	%	100	%

Con Edison has established a pension trust for the investment of assets to be used for the exclusive purpose of providing retirement benefits to participants and beneficiaries and payment of plan expenses.

Pursuant to resolutions adopted by Con Edison’s Board of Directors, the Management Development and Compensation Committee of the Board of Directors (the Committee) has general oversight responsibility for Con Edison’s pension and other employee benefit plans. The pension plan’s named fiduciaries have been granted the authority to control and manage the operation and administration of the plans, including overall responsibility for the investment of assets in the trust and the power to appoint and terminate investment managers.

The investment objectives of the Con Edison pension plan are to maintain a level and form of assets adequate to meet benefit obligations to participants, to achieve the expected long-term total return on the trust assets within a prudent level of risk and maintain a level of volatility that is not expected to have a material impact on the Company’s expected contribution and expense or the Company’s ability to meet plan obligations. The assets of the plan have no significant concentration of risk in one country (other than the United States), industry or entity.

The strategic asset allocation is intended to meet the objectives of the pension plan by diversifying its funds across asset classes, investment styles and fund managers. An asset/liability study typically is conducted every few years to determine whether the current strategic asset allocation continues to represent the appropriate balance of expected risk and reward for the plan to meet expected liabilities. Each study considers the investment risk of the asset allocation and determines the optimal asset allocation for the plan. The target asset allocation for 2016 reflects the results of such a study conducted in 2011.

Individual fund managers operate under written guidelines provided by Con Edison, which cover such areas as investment objectives, performance measurement, permissible investments, investment restrictions, trading and execution, and communication and reporting requirements. Con Edison management regularly monitors, and the named fiduciaries review and report to the Committee regarding, asset class performance, total fund performance, and compliance with asset allocation guidelines. Management changes fund managers and rebalances the portfolio as appropriate. At the direction of the named fiduciaries, such changes are reported to the Committee.

Assets measured at fair value on a recurring basis are summarized below under a three-level hierarchy as defined by the accounting rules for fair value measurements (see Note P).

The fair values of the pension plan assets at December 31, 2015 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Level 3		Total
U.S. Equity (a)	$3,106		$—		$—	$3,106
International Equity (b)	2,874	346		—		3,220
Private Equity (c)	—	—		170		170
U.S. Government Issued Debt (d)	—	2,222		—		2,222
Corporate Bonds Debt (e)	—	1,356		—		1,356
Structured Assets Debt (f)	—	1		—		1
Other Fixed Income Debt (g)	—	170		—		170
Real Estate (h)	—	—		1,248		1,248
Cash and Cash Equivalents (i)	115	414		—		529
Futures (j)	161	132		—		293
Hedge Funds (k)	—	—		233		233
Total investments	$6,256	$4,641		$1,651		$12,548
Funds for retiree health benefits (l)	(162)	(120)		(43)		(325)
Investments (excluding funds for retiree health benefits)	$6,094	$4,521		$1,608		$12,223
Pending activities (m)						(464)
Total fair value of plan net assets						$11,759


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	Private Equity consists of global equity funds that are not exchange-traded.


(d)	U.S. Government Issued Debt includes agency and treasury securities.


(e)	Corporate Bonds Debt consists of debt issued by various corporations.


(f)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(g)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(h)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(i)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(j)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)

The Companies set aside funds for retiree health benefits through a separate account within the pension trust, as permitted under Section 401(h) of the Internal Revenue Code of 1986, as amended. In accordance with the Code, the plan’s investments in the 401(h) account may not be used for, or diverted to, any purpose other than providing health benefits for retirees. The net assets held in the 401(h) account are calculated based on a pro-rata percentage allocation of the net assets in the pension plan. The related obligations for health benefits are not included in the pension plan’s obligations and are included in the Companies’ other postretirement benefit obligation. See Note F.


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2015 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2015	Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	Assets Sold During the Year – Realized Gains/(Losses)	Purchases Sales and Settlements	Transfer In/(Out) of Level 3		Ending Balance as of December 31, 2015
Real Estate	$1,137	$131	$12	$(32)		$—	$1,248
Private Equity	114	17	—	39	—		170
Hedge Funds	224	3	—	6	—		233
Total investments	$1,475	$151	$12	$13		$—	$1,651
Funds for retiree health benefits	(43)	—	—	—	—		(43)
Investments (excluding funds for retiree health benefits)	$1,432	$151	$12	$13		$—	$1,608

The fair values of the pension plan assets at December 31, 2014 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Level 3		Total
U.S. Equity (a)	$3,168		$—		$—	$3,168
International Equity (b)	2,841	361		—		3,202
Private Equity (c)	—	—		114		114
U.S. Government Issued Debt (d)	—	2,113		—		2,113
Corporate Bonds Debt (e)	—	1,351		—		1,351
Structured Assets Debt (f)	—	4		—		4
Other Fixed Income Debt (g)	—	208		—		208
Real Estate (h)	—	—		1,137		1,137
Cash and Cash Equivalents (i)	188	477		—		665
Futures (j)	192	37		—		229
Hedge Funds (k)	—	—		224		224
Total investments	$6,389	$4,551		$1,475		$12,415
Funds for retiree health benefits (l)	(184)	(131)		(43)		(358)
Investments (excluding funds for retiree health benefits)	$6,205	$4,420		$1,432		$12,057
Pending activities (m)						(562)
Total fair value of plan net assets						$11,495


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	Private Equity consists of global equity funds that are not exchange-traded.


(d)	U.S. Government Issued Debt includes agency and treasury securities.


(e)	Corporate Bonds Debt consists of debt issued by various corporations.


(f)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(g)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(h)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(i)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(j)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2014 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2014	Assets Still Held at Reporting Date – Unrealized Gains/(Losses)	Assets Sold During the Year – Realized Gains/(Losses)	Purchases Sales and Settlements	Transfer In/(Out) of Level 3		Ending Balance as of December 31, 2014
Real Estate	$1,062	$86	$20	$(31)		$—	$1,137
Private Equity	67	12	—	35	—		114
Hedge Funds	206	11	—	7	—		224
Total investments	$1,335	$109	$20	$11		$—	$1,475
Funds for retiree health benefits	(42)	(1)	—	—	—		(43)
Investments (excluding funds for retiree health benefits)	$1,293	$108	$20	$11		$—	$1,432

The Companies also offer a defined contribution savings plan that covers substantially all employees and made contributions to the plan as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$34	$32	$30
CECONY	29	27	26

Mortality Table Revision

The Companies adopted revised mortality tables effective December 31, 2014 in the measurement of its pension and other postretirement benefit plan obligations, accounting costs and required contribution amounts. The revised tables reflect the RP-2014 mortality tables published by the Society of Actuaries in October 2014, as adjusted based on the actual experience of the Companies. The new tables incorporate substantial life expectancy improvements relative to the last tables published in 2000 (RP-2000). As a result of the adoption, Con Edison recognized an increase in its pension benefit obligation of approximately $800 million as of December 31, 2014. The Companies, under their current New York rate plans, defer as a regulatory asset or liability, as the case may be, the differences between the actual level of expenses for pension and other postretirement benefits and amounts for those expenses reflected in rates.

CECONY

Defined Benefit Plan Disclosure [Line Items]

Pension Benefits

Total Periodic Benefit Cost

The components of the Companies’ total periodic benefit costs for 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Service cost – including administrative expenses	$297	$227	$267	$279	$211	$249
Interest cost on projected benefit obligation	575	572	537	538	536	503
Expected return on plan assets	(886)	(832)	(750)	(840)	(789)	(713)
Recognition of net actuarial loss	775	618	832	734	586	788
Recognition of prior service costs	4	4	5	2	2	4
NET PERIODIC BENEFIT COST	$765	$589	$891	$713	$546	$831
Amortization of regulatory asset (a)	1	2	2	1	2	2
TOTAL PERIODIC BENEFIT COST	$766	$591	$893	$714	$548	$833
Cost capitalized	(301)	(225)	(348)	(285)	(212)	(327)
Reconciliation to rate level	(74)	118	(84)	(74)	108	(87)
Cost charged to operating expenses	$391	$484	$461	$355	$444	$419

(a) Relates to an increase in CECONY’s pension obligation of $45 million from a 1999 special retirement program.

Funded Status

The funded status at December 31, 2015, 2014 and 2013 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$15,081	$12,197	$13,406	$14,137	$11,429	$12,572
Service cost – excluding administrative expenses	293	221	259	274	206	241
Interest cost on projected benefit obligation	575	572	537	538	536	503
Net actuarial (gain)/loss	(996)	2,641	(1,469)	(931)	2,484	(1,388)
Plan amendments	—	6	—	—	—	—
Benefits paid	(576)	(556)	(536)	(536)	(518)	(499)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$14,377	$15,081	$12,197	$13,482	$14,137	$11,429
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$11,495	$10,755	$9,135	$10,897	$10,197	$8,668
Actual return on plan assets	126	752	1,310	118	715	1,241
Employer contributions	750	578	879	697	535	819
Benefits paid	(576)	(556)	(536)	(536)	(518)	(499)
Administrative expenses	(36)	(34)	(33)	(35)	(32)	(32)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$11,759	$11,495	$10,755	$11,141	$10,897	$10,197
FUNDED STATUS	$(2,618)	$(3,586)	$(1,442)	$(2,341)	$(3,240)	$(1,232)
Unrecognized net loss	$3,909	$4,888	$2,759	$3,704	$4,616	$2,617
Unrecognized prior service costs	16	20	17	3	4	6
Accumulated benefit obligation	12,909	13,454	11,004	12,055	12,553	10,268

Assumptions

The actuarial assumptions were as follows:



	2015		2014		2013
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	4.25	%	3.90	%	4.80	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.35	%
O&R	4.00	%	4.00	%	4.25	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	3.90	%	4.80	%	4.10	%
Expected return on plan assets	7.80	%	8.00	%	8.00	%
Rate of compensation increase
CECONY	4.25	%	4.35	%	4.35	%
O&R	4.00	%	4.25	%	4.25	%

Discount Rate Assumption

Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years:



(Millions of Dollars)	2016	2017	2018	2019	2020	2021-2025
Con Edison	$614	$636	$658	$680	$701	$3,800
CECONY	572	593	614	635	655	3,548

Expected Contributions

Plan Assets

The asset allocations for the pension plan at the end of 2015, 2014 and 2013, and the target allocation for 2016 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2016	2015		2014		2013
Equity Securities	55% - 65%	57	%	58	%	60	%
Debt Securities	27% - 33%	33	%	32	%	30	%
Real Estate	8% - 12%	10	%	10	%	10	%
Total	100%	100	%	100	%	100	%

Assets measured at fair value on a recurring basis are summarized below under a three-level hierarchy as defined by the accounting rules for fair value measurements (see Note P).

The fair values of the pension plan assets at December 31, 2015 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Level 3		Total
U.S. Equity (a)	$3,106		$—		$—	$3,106
International Equity (b)	2,874	346		—		3,220
Private Equity (c)	—	—		170		170
U.S. Government Issued Debt (d)	—	2,222		—		2,222
Corporate Bonds Debt (e)	—	1,356		—		1,356
Structured Assets Debt (f)	—	1		—		1
Other Fixed Income Debt (g)	—	170		—		170
Real Estate (h)	—	—		1,248		1,248
Cash and Cash Equivalents (i)	115	414		—		529
Futures (j)	161	132		—		293
Hedge Funds (k)	—	—		233		233
Total investments	$6,256	$4,641		$1,651		$12,548
Funds for retiree health benefits (l)	(162)	(120)		(43)		(325)
Investments (excluding funds for retiree health benefits)	$6,094	$4,521		$1,608		$12,223
Pending activities (m)						(464)
Total fair value of plan net assets						$11,759


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	Private Equity consists of global equity funds that are not exchange-traded.


(d)	U.S. Government Issued Debt includes agency and treasury securities.


(e)	Corporate Bonds Debt consists of debt issued by various corporations.


(f)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(g)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(h)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(i)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(j)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2015 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2015	Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	Assets Sold During the Year – Realized Gains/(Losses)	Purchases Sales and Settlements	Transfer In/(Out) of Level 3		Ending Balance as of December 31, 2015
Real Estate	$1,137	$131	$12	$(32)		$—	$1,248
Private Equity	114	17	—	39	—		170
Hedge Funds	224	3	—	6	—		233
Total investments	$1,475	$151	$12	$13		$—	$1,651
Funds for retiree health benefits	(43)	—	—	—	—		(43)
Investments (excluding funds for retiree health benefits)	$1,432	$151	$12	$13		$—	$1,608

The fair values of the pension plan assets at December 31, 2014 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Level 3		Total
U.S. Equity (a)	$3,168		$—		$—	$3,168
International Equity (b)	2,841	361		—		3,202
Private Equity (c)	—	—		114		114
U.S. Government Issued Debt (d)	—	2,113		—		2,113
Corporate Bonds Debt (e)	—	1,351		—		1,351
Structured Assets Debt (f)	—	4		—		4
Other Fixed Income Debt (g)	—	208		—		208
Real Estate (h)	—	—		1,137		1,137
Cash and Cash Equivalents (i)	188	477		—		665
Futures (j)	192	37		—		229
Hedge Funds (k)	—	—		224		224
Total investments	$6,389	$4,551		$1,475		$12,415
Funds for retiree health benefits (l)	(184)	(131)		(43)		(358)
Investments (excluding funds for retiree health benefits)	$6,205	$4,420		$1,432		$12,057
Pending activities (m)						(562)
Total fair value of plan net assets						$11,495


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	Private Equity consists of global equity funds that are not exchange-traded.


(d)	U.S. Government Issued Debt includes agency and treasury securities.


(e)	Corporate Bonds Debt consists of debt issued by various corporations.


(f)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(g)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(h)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(i)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(j)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2014 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2014	Assets Still Held at Reporting Date – Unrealized Gains/(Losses)	Assets Sold During the Year – Realized Gains/(Losses)	Purchases Sales and Settlements	Transfer In/(Out) of Level 3		Ending Balance as of December 31, 2014
Real Estate	$1,062	$86	$20	$(31)		$—	$1,137
Private Equity	67	12	—	35	—		114
Hedge Funds	206	11	—	7	—		224
Total investments	$1,335	$109	$20	$11		$—	$1,475
Funds for retiree health benefits	(42)	(1)	—	—	—		(43)
Investments (excluding funds for retiree health benefits)	$1,293	$108	$20	$11		$—	$1,432

The Companies also offer a defined contribution savings plan that covers substantially all employees and made contributions to the plan as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$34	$32	$30
CECONY	29	27	26

Mortality Table Revision

Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Other Postretirement Benefits

The Utilities currently have contributory comprehensive hospital, medical and prescription drug programs for eligible retirees, their dependents and surviving spouses.

Total Periodic Benefit Cost

The components of the Companies’ total periodic postretirement benefit costs for 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Service cost	$20	$19	$23	$15	$15	$18
Interest cost on accumulated other postretirement benefit obligation	51	60	54	43	52	46
Expected return on plan assets	(78)	(77)	(77)	(68)	(68)	(68)
Recognition of net actuarial loss	31	57	65	28	51	57
Recognition of prior service cost	(20)	(19)	(27)	(14)	(15)	(23)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST	$4	$40	$38	$4	$35	$30
Cost capitalized	(2)	(15)	(15)	(2)	(14)	(12)
Reconciliation to rate level	14	10	58	6	2	50
Cost charged to operating expenses	$16	$35	$81	$8	$23	$68

Funded Status

The funded status of the programs at December 31, 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,411	$1,395	$1,454	$1,203	$1,198	$1,238
Service cost	20	19	23	15	15	18
Interest cost on accumulated postretirement benefit obligation	51	60	54	43	52	46
Amendments	—	(12)	—	—	—	—
Net actuarial loss/(gain)	(103)	47	(42)	(85)	28	(20)
Benefits paid and administrative expenses	(127)	(134)	(136)	(117)	(125)	(126)
Participant contributions	35	36	38	34	35	38
Medicare prescription subsidy	—	—	4	—	—	4
BENEFIT OBLIGATION AT END OF YEAR	$1,287	$1,411	$1,395	$1,093	$1,203	$1,198
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$1,084	$1,113	$1,047	$950	$977	$922
Actual return on plan assets	(6)	59	153	(4)	54	134
Employer contributions	6	7	9	6	7	9
EGWP payments	28	12	8	26	11	7
Participant contributions	35	36	38	34	35	38
Benefits paid	(153)	(143)	(142)	(142)	(134)	(133)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$994	$1,084	$1,113	$870	$950	$977
FUNDED STATUS	$(293)	$(327)	$(282)	$(223)	$(253)	$(221)
Unrecognized net loss	$28	$78	$70	$4	$45	$54
Unrecognized prior service costs	(51)	(71)	(78)	(32)	(46)	(61)

Assumptions

The actuarial assumptions were as follows:



	2015		2014		2013
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	4.05	%	3.75	%	4.50	%
O&R	4.20	%	3.85	%	4.75	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	3.75	%	4.50	%	3.75	%
O&R	3.85	%	4.75	%	4.05	%
Expected Return on Plan Assets	7.75	%	7.75	%	7.75	%

Refer to Note E for descriptions of the basis for determining the expected return on assets, investment policies and strategies and the assumed discount rate.

A one-percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2016:



	Con Edison		CECONY
	1-Percentage-Point
(Millions of Dollars)	Increase	Decrease	Increase	Decrease
Effect on accumulated other postretirement benefit obligation	$(18)	$41	$(37)	$56
Effect on service cost and interest cost components for 2015	(1)	1	(3)	2

Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years, net of receipt of governmental subsidies:



(Millions of Dollars)	2016	2017	2018	2019	2020	2021-2025
Con Edison	$95	$93	$91	$88	$85	$403
CECONY	85	83	81	78	75	348

Expected Contributions

Plan Assets

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2015, 2014 and 2013, and the target allocation for 2016 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2016	2015		2014		2013
Equity Securities	57% - 73%	59	%	59	%	61	%
Debt Securities	26% - 44%	41	%	41	%	39	%
Total	100%	100	%	100	%	100	%

Refer to Note E for a discussion of Con Edison’s investment policy for its benefit plans.

The fair values of the plan assets at December 31, 2015 by asset category as defined by the accounting rules for fair value measurements (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Level 3		Total
Equity (a)		$—	$393		$—	$393
Other Fixed Income Debt (b)	—		260	—		260
Cash and Cash Equivalents (c)	—		7	—		7
Total investments		$—	$660		$—	$660
Funds for retiree health benefits (d)	162		120	43		325
Investments (including funds for retiree health benefits)	$162		$780	$43		$985
Pending activities (e)						9
Total fair value of plan net assets						$994


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Barclays Capital Aggregate Index.


(c)	Cash and Cash Equivalents include short term investments and money markets.

(d)


(e)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year end.

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2015 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2015		Assets Still Held at Reporting Date – Unrealized Gains/(Losses)		Assets Sold During the Year – Realized Gains/(Losses)		Purchases Sales and Settlements		Transfers In/(Out) of Level 3		Ending Balance as of December 31, 2015
Total investments		$—		$—		$—		$—		$—		$—
Funds for retiree health benefits	43		—		—		—		—		43
Investments (including funds for retiree health benefits)	$43			$—		$—		$—		$—	$43

The fair values of the plan assets at December 31, 2014 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Level 3		Total
Equity (a)		$—	$428		$—	$428
Other Fixed Income Debt (b)	—		286	—		286
Cash and Cash Equivalents (c)	—		11	—		11
Total investments		$—	$725		$—	$725
Funds for retiree health benefits (d)	184		131	43		358
Investments (including funds for retiree health benefits)	$184		$856	$43		$1,083
Pending activities (e)						1
Total fair value of plan net assets						$1,084


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Barclays Capital Aggregate Index.


(c)	Cash and Cash Equivalents include short term investments and money markets.

(d)


(e)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year end.

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2014 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2014		Assets Still Held at Reporting Date – Unrealized Gains/(Losses)		Assets Sold During the Year – Realized Gains/(Losses)		Purchases Sales and Settlements		Transfers In/(Out) of Level 3		Ending Balance as of December 31, 2014
Total investments		$—		$—		$—		$—		$—		$—
Funds for retiree health benefits	42		1		—		—		—		43
Investments (including funds for retiree health benefits)	$42		$1			$—		$—		$—	$43

Mortality Table Revision

The Companies adopted revised mortality tables effective December 31, 2014 in the measurement of its pension and other postretirement benefit plan obligations, accounting costs, and required contribution amounts as discussed in Note E. As a result of the adoption, Con Edison recognized an increase of less than $10 million in its other postretirement benefits obligation as of December 31, 2014. The Companies, under their current New York rate plans, defer as a regulatory asset or liability, as the case may be, the differences between the actual level of expenses for pension and other postretirement benefits and amounts for those expenses reflected in rates.

Environmental Matters

12 Months Ended

Dec. 31, 2015

Site Contingency [Line Items]

Environmental Matters

Superfund Sites

Hazardous substances, such as asbestos, polychlorinated biphenyls (PCBs) and coal tar, have been used or generated in the course of operations of the Utilities and their predecessors and are present at sites and in facilities and equipment they currently or previously owned, including sites at which gas was manufactured or stored.

The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 and similar state statutes (Superfund) impose joint and several liability, regardless of fault, upon generators of hazardous substances for investigation and remediation costs (which include costs of demolition, removal, disposal, storage, replacement, containment and monitoring) and natural resource damages. Liability under these laws can be material and may be imposed for contamination from past acts, even though such past acts may have been lawful at the time they occurred. The sites at which the Utilities have been asserted to have liability under these laws, including their manufactured gas plant sites and any neighboring areas to which contamination may have migrated, are referred to herein as “Superfund Sites.”

For Superfund Sites where there are other potentially responsible parties and the Utilities are not managing the site investigation and remediation, the accrued liability represents an estimate of the amount the Utilities will need to pay to investigate and, where determinable, discharge their related obligations. For Superfund Sites (including the manufactured gas plant sites) for which one of the Utilities is managing the investigation and remediation, the accrued liability represents an estimate of the company’s share of the undiscounted cost to investigate the sites and, for sites that have been investigated in whole or in part, the cost to remediate the sites, if remediation is necessary and if a reasonable estimate of such cost can be made. Remediation costs are estimated in light of the information available, applicable remediation standards and experience with similar sites.

The accrued liabilities and regulatory assets related to Superfund Sites at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Accrued Liabilities:
Manufactured gas plant sites	$679	$684	$579	$587
Other Superfund Sites	86	80	86	79
Total	$765	$764	$665	$666
Regulatory assets	$904	$925	$800	$820

Most of the accrued Superfund Site liability relates to sites that have been investigated, in whole or in part. However, for some of the sites, the extent and associated cost of the required remediation has not yet been determined. As investigations progress and information pertaining to the required remediation becomes available, the Utilities expect that additional liability may be accrued, the amount of which is not presently determinable but may be material. Con Edison and CECONY estimate that in 2016 they will incur costs for remediation of approximately $51 million and $36 million, respectively. The Companies are unable to estimate the time period over which the remaining accrued liability will be incurred because, among other things, the required remediation has not been determined for some of the sites. Under their current rate plans, the Utilities are permitted to recover or defer as regulatory assets (for subsequent recovery through rates) certain site investigation and remediation costs.

Environmental remediation costs incurred and insurance recoveries received related to Superfund Sites at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Remediation costs incurred	$37	$29	$34	$20
Insurance recoveries received (a)	—	7	—	7

(a) Reduced amount deferred for recovery from customers

In 2015, Con Edison and CECONY estimated that for their manufactured gas plant sites (including CECONY’s Astoria site), the aggregate undiscounted potential liability for the investigation and remediation of coal tar and/or other environmental contaminants could range up to $2.8 billion and $2.7 billion, respectively. These estimates were based on the assumption that there is contamination at all sites, including those that have not yet been fully investigated and additional assumptions about the extent of the contamination and the type and extent of the remediation that may be required. Actual experience may be materially different.

Asbestos Proceedings

Suits have been brought in New York State and federal courts against the Utilities and many other defendants, wherein a large number of plaintiffs sought large amounts of compensatory and punitive damages for deaths and injuries allegedly caused by exposure to asbestos at various premises of the Utilities. The suits that have been resolved, which are many, have been resolved without any payment by the Utilities or for amounts that were not, in the aggregate, material to them. The amounts specified in all the remaining thousands of suits total billions of dollars; however, the Utilities believe that these amounts are greatly exaggerated, based on the disposition of previous claims. Con Edison and CECONY have accrued their estimated aggregate undiscounted potential liabilities for these suits and additional suits that may be brought over the next 15 years as shown in the following table. These estimates were based upon a combination of modeling, historical data analysis and risk factor assessment. Trial courts have begun, and unless otherwise determined by an appellate court may continue, to apply a different standard for determining liability in asbestos suits than the standard that applied historically. As a result, the Companies currently believe that there is a reasonable possibility of an exposure to loss in excess of the liability accrued for the suits. The Companies are unable to estimate the amount or range of such loss. In addition, certain current and former employees have claimed or are claiming workers’ compensation benefits based on alleged disability from exposure to asbestos. Under its current rate plans, CECONY is permitted to defer as regulatory assets (for subsequent recovery through rates) costs incurred for its asbestos lawsuits and workers’ compensation claims. The accrued liability for asbestos suits and workers’ compensation proceedings (including those related to asbestos exposure) and the amounts deferred as regulatory assets for the Companies at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Accrued liability – asbestos suits	$8	$8	$7	$7
Regulatory assets – asbestos suits	$8	$8	$7	$7
Accrued liability – workers’ compensation	$86	$83	$81	$78
Regulatory assets – workers’ compensation	$11	$8	$11	$8

CECONY

Site Contingency [Line Items]

Environmental Matters

Superfund Sites

The accrued liabilities and regulatory assets related to Superfund Sites at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Accrued Liabilities:
Manufactured gas plant sites	$679	$684	$579	$587
Other Superfund Sites	86	80	86	79
Total	$765	$764	$665	$666
Regulatory assets	$904	$925	$800	$820

Environmental remediation costs incurred and insurance recoveries received related to Superfund Sites at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Remediation costs incurred	$37	$29	$34	$20
Insurance recoveries received (a)	—	7	—	7

(a) Reduced amount deferred for recovery from customers

Asbestos Proceedings



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Accrued liability – asbestos suits	$8	$8	$7	$7
Regulatory assets – asbestos suits	$8	$8	$7	$7
Accrued liability – workers’ compensation	$86	$83	$81	$78
Regulatory assets – workers’ compensation	$11	$8	$11	$8

Other Material Contingencies

12 Months Ended

Dec. 31, 2015

Guarantor Obligations [Line Items]

Other Material Contingencies

Manhattan Steam Main Rupture

In July 2007, a CECONY steam main located in midtown Manhattan ruptured. It has been reported that one person died and others were injured as a result of the incident. Several buildings in the area were damaged. Debris from the incident included dirt and mud containing asbestos. The response to the incident required the closing of several buildings and streets for various periods. Approximately ninety suits are pending against the company seeking generally unspecified compensatory and, in some cases, punitive damages, for wrongful death, personal injury, property damage and business interruption. The company has notified its insurers of the incident and believes that the policies in force at the time of the incident will cover the company’s costs to satisfy its liability to others in connection with the suits. In the company’s estimation, there is not a reasonable possibility that an exposure to loss exists for the suits that is materially in excess of the estimated liability accrued. At December 31, 2015, the company has accrued its estimated liability for the suits of $50 million and an insurance receivable in the same amount.

Manhattan Explosion and Fire

On March 12, 2014, two multi-use five-story tall buildings located on Park Avenue between 116th and 117th Street in Manhattan were destroyed by an explosion and fire. CECONY had delivered gas to the buildings through service lines from a distribution main located below ground on Park Avenue. Eight people died and more than 50 people were injured. Additional buildings were also damaged. The National Transportation Safety Board (NTSB) investigated. The parties to the investigation included the company, the City of New York, the Pipeline and Hazardous Materials Safety Administration and the NYSPSC (which also conducted an investigation). In June 2015, the NTSB issued a final report concerning the incident, its probable cause and safety recommendations. The NTSB determined that the probable cause of the incident was (1) the failure of a defective fusion joint at a service tee (which joined a plastic service line to a plastic distribution main) installed by the company that allowed gas to leak from the distribution main and migrate into a building where it ignited and (2) a breach in a City sewer line that allowed groundwater and soil to flow into the sewer, resulting in a loss of support for the distribution main, which caused it to sag and overstressed the defective fusion joint. The NTSB also made safety recommendations, including recommendations to the company that addressed its procedures for the preparation and examination of plastic fusions, training of its staff on conditions for notifications to the City’s Fire Department and extension of its gas main isolation valve installation program. Approximately seventy suits are pending against the company seeking generally unspecified damages and, in one case, punitive damages, for wrongful death, personal injury, property damage and business interruption. The company has notified its insurers of the incident and believes that the policies in force at the time of the incident will cover the company’s costs, in excess of a required retention (the amount of which is not material), to satisfy any liability it may have for damages in connection with the incident. The company is unable to estimate the amount or range of its possible loss related to the incident. At December 31, 2015, the company had not accrued a liability for the incident.

Other Contingencies

See “Other Regulatory Matters” in Note B and "Uncertain Tax Positions" in Note L.

Guarantees

Con Edison and its subsidiaries enter into various agreements providing financial or performance assurance primarily to third parties on behalf of their subsidiaries. Maximum amounts guaranteed by Con Edison totaled $2,856 million and $2,547 million at December 31, 2015 and 2014, respectively.

A summary, by type and term, of Con Edison’s total guarantees at December 31, 2015 is as follows:



Guarantee Type	0 – 3 years	4 – 10 years	> 10 years		Total
	(Millions of Dollars)
NY Transco	$791	$567		$—	$1,358
Energy transactions	792	35	97		924
Renewable electric production projects	471	1	27		499
Other	75	—	—		75
Total	$2,129	$603	$124		$2,856

NY Transco – Con Edison has guaranteed payment by CET Electric of the contributions it agreed to make to New York Transco LLC (NY Transco). CET Electric acquired a 45.7 percent interest in NY Transco when it was formed in 2014. NY Transco’s transmission projects are being developed initially by CECONY and other New York transmission owners and are expected to be sold to NY Transco. The development of the projects would be subject to authorizations from the NYSPSC, the FERC and other federal, state and local agencies. Guarantee amount shown is for the maximum possible required amount of CET Electric's contributions, which assumes that all of the NY Transco projects proposed when NY Transco was formed receive all required regulatory approvals and are completed at 175 percent of their estimated costs and that NY Transco does not use any debt financing to construct the projects. Guarantee term shown is assumed as the timing of the contributions is not certain.

Energy Transactions – Con Edison guarantees payments on behalf of its competitive energy businesses in order to facilitate physical and financial transactions in gas, pipeline capacity, oil, electricity, renewable energy credits and energy services. To the extent that liabilities exist under the contracts subject to these guarantees, such liabilities are included in Con Edison’s consolidated balance sheet.

Renewable Electric Production Projects – Con Edison, Con Edison Development and Con Edison Solutions guarantee payments associated with investments in solar and wind energy facilities by their wholly-owned subsidiaries.

Other – Other guarantees primarily relate to $70 million in guarantees provided by Con Edison to Travelers Insurance Company for indemnity agreements for surety bonds in connection with energy service projects and operation of solar energy facilities of Con Edison Solutions and Con Edison Development, respectively. In addition, Con Edison issued a guarantee to the Public Utility Commission of Texas covering obligations of Con Edison Solutions as a retail electric provider. Con Edison’s estimate of the maximum potential obligation for this guarantee is $5 million as of December 31, 2015.

CECONY

Guarantor Obligations [Line Items]

Other Material Contingencies

Manhattan Steam Main Rupture

Manhattan Explosion and Fire

Other Contingencies

See “Other Regulatory Matters” in Note B and "Uncertain Tax Positions" in Note L.

Guarantees

A summary, by type and term, of Con Edison’s total guarantees at December 31, 2015 is as follows:



Guarantee Type	0 – 3 years	4 – 10 years	> 10 years		Total
	(Millions of Dollars)
NY Transco	$791	$567		$—	$1,358
Energy transactions	792	35	97		924
Renewable electric production projects	471	1	27		499
Other	75	—	—		75
Total	$2,129	$603	$124		$2,856

Electricity Purchase Agreements

12 Months Ended

Dec. 31, 2015

Long-term Contract for Purchase of Electric Power [Line Items]

Electricity Purchase Agreements

The Utilities have electricity purchase agreements with non-utility generators and others for generating capacity. The Utilities recover their purchased power costs in accordance with provisions approved by the applicable state public utility regulators. See “Recoverable Energy Costs” in Note A.

At December 31, 2015, the significant terms of the electricity purchase agreements with non-utility generators were as follows:



Facility	Equity Owner	Plant Output (MW)	Contracted Output (MW)	Contract Start Date	Contract Term (Years)
Brooklyn Navy Yard	Brooklyn Navy Yard Cogeneration Partners, LP	322	299	November 1996	40
Linden Cogeneration	Cogen Technologies Linden Venture, LP	1,035	609	May 1992	25
Indian Point	Entergy Nuclear Power Marketing, LLC	2,311	500	August 2001	16
Astoria Energy	Astoria Energy, LLC	640	500	May 2006	10

The Utilities also conducted auctions and have entered into various other electricity purchase agreements. Assuming performance by the parties to the electricity purchase agreements, the Utilities are obligated over the terms of the agreements to make capacity and other fixed payments.

The future capacity and other fixed payments under the contracts are estimated to be as follows:



(Millions of Dollars)	2016	2017	2018	2019	2020	All Years Thereafter
Con Edison	$222	$207	$181	$98	$53	$762
CECONY	218	205	181	98	53	762

For energy delivered under most of the electricity purchase agreements, CECONY is obligated to pay variable prices. The company’s payments under the agreements for capacity, energy and other fixed payments in 2015, 2014 and 2013 were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Linden Cogeneration	$323	$381	$346
Indian Point	226	247	220
Astoria Energy	178	230	183
Brooklyn Navy Yard	113	133	118
Indeck Corinth (a)	25	80	79
Selkirk (b)	—	144	215
Independence (b)	—	97	121
Total	$865	$1,312	$1,282

(a) Contract term ended in 2015.

(b) Contract term ended in 2014.

CECONY

Long-term Contract for Purchase of Electric Power [Line Items]

Electricity Purchase Agreements

At December 31, 2015, the significant terms of the electricity purchase agreements with non-utility generators were as follows:



Facility	Equity Owner	Plant Output (MW)	Contracted Output (MW)	Contract Start Date	Contract Term (Years)
Brooklyn Navy Yard	Brooklyn Navy Yard Cogeneration Partners, LP	322	299	November 1996	40
Linden Cogeneration	Cogen Technologies Linden Venture, LP	1,035	609	May 1992	25
Indian Point	Entergy Nuclear Power Marketing, LLC	2,311	500	August 2001	16
Astoria Energy	Astoria Energy, LLC	640	500	May 2006	10

The future capacity and other fixed payments under the contracts are estimated to be as follows:



(Millions of Dollars)	2016	2017	2018	2019	2020	All Years Thereafter
Con Edison	$222	$207	$181	$98	$53	$762
CECONY	218	205	181	98	53	762



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Linden Cogeneration	$323	$381	$346
Indian Point	226	247	220
Astoria Energy	178	230	183
Brooklyn Navy Yard	113	133	118
Indeck Corinth (a)	25	80	79
Selkirk (b)	—	144	215
Independence (b)	—	97	121
Total	$865	$1,312	$1,282

(a) Contract term ended in 2015.

(b) Contract term ended in 2014.

Leases

12 Months Ended

Dec. 31, 2015

Operating Leased Assets [Line Items]

Leases

Con Edison’s subsidiaries lease electric transmission facilities, gas distribution facilities, land, office buildings and equipment. In accordance with the accounting rules for leases, these leases are classified as either capital leases or operating leases. Most of the operating leases provide the option to renew at the fair rental value for future periods. Generally, it is expected that leases will be renewed or replaced in the normal course of business.

Capital leases: For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. The following assets under capital leases are included in the Companies’ consolidated balance sheets at December 31, 2015 and 2014:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
UTILITY PLANT
Common	$3	$3	$2	$1

The accumulated amortization of the capital leases for Con Edison and CECONY was $3 million and $2 million, respectively at December 31, 2015, and $2 million and $1 million, respectively at December 31, 2014.

The future minimum lease commitments for the above assets are as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$1	$1
2017	1	1
2018	1	1
2019	—	—
2020	—	—
All years thereafter	—	—
Total	3	3
Less: amount representing interest	1	1
Present value of net minimum lease payment	$2	$2

Operating leases: The future minimum lease commitments under the Companies’ non-cancelable operating lease agreements are as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$18	$12
2017	18	12
2018	18	12
2019	16	10
2020	15	9
All years thereafter	123	42
Total	$208	$97

Lease In/Lease Out Transactions

In each of 1997 and 1999, Con Edison Development entered into transactions in which it leased property and then immediately subleased the properties back to the lessor (termed “Lease In/Lease Out,” or LILO transactions). The transactions respectively involved electric generating and gas distribution facilities in the Netherlands. In accordance with the accounting rules for leases, Con Edison accounted for the two LILO transactions as leveraged leases.

In 2013, the Court of Appeals for the Federal Circuit reversed a lower court decision and disallowed tax losses in connection with the 1997 LILO transaction and Con Edison entered into a closing agreement with the Internal Revenue Service (IRS) regarding the 1997 and 1999 LILO transactions. In addition, in 2013, Con Edison recorded an after-tax charge of $150 million to reflect, as required by the accounting rules for leveraged lease transactions, the recalculation of the accounting effect of the LILO transactions based on the revised after-tax cash flows projected from the inception of the leveraged leases as well as the interest on the potential tax liability resulting from the disallowance of federal and state income tax losses for the LILO transactions. Also, in 2013, the LILO transactions were terminated, as a result of which the company realized a $55 million gain (after-tax). In 2014, adjustments were made to the interest accrued on the liability and the related taxes resulting in a decrease to net income of $1 million. Adjustments made in 2015 were immaterial.

The effect on Con Edison’s consolidated income statement for the twelve months ended as of December 31, 2014 and 2013 was as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2014		2013
Increase/(decrease) to non-utility operating revenues		$—	$(27)
(Increase)/decrease to other interest expense	13		(131)
Income tax benefit/(expense)	(14)		63
Total increase/(decrease) in net income	$(1)		$(95)

CECONY

Operating Leased Assets [Line Items]

Leases



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
UTILITY PLANT
Common	$3	$3	$2	$1

The future minimum lease commitments for the above assets are as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$1	$1
2017	1	1
2018	1	1
2019	—	—
2020	—	—
All years thereafter	—	—
Total	3	3
Less: amount representing interest	1	1
Present value of net minimum lease payment	$2	$2

Operating leases: The future minimum lease commitments under the Companies’ non-cancelable operating lease agreements are as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$18	$12
2017	18	12
2018	18	12
2019	16	10
2020	15	9
All years thereafter	123	42
Total	$208	$97

Lease In/Lease Out Transactions

The effect on Con Edison’s consolidated income statement for the twelve months ended as of December 31, 2014 and 2013 was as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2014		2013
Increase/(decrease) to non-utility operating revenues		$—	$(27)
(Increase)/decrease to other interest expense	13		(131)
Income tax benefit/(expense)	(14)		63
Total increase/(decrease) in net income	$(1)		$(95)

Goodwill	12 Months Ended
Goodwill	Dec. 31, 2015
Goodwill [Line Items]
Goodwill	Goodwill In 2015 and 2014, Con Edison completed impairment tests for its goodwill of $406 million related to the O&R merger, and determined that it was not impaired. For the impairment test, $245 million and $161 million of the goodwill were allocated to CECONY and O&R, respectively. In 2015 and 2014, Con Edison also completed impairment tests for the goodwill of $23 million related to two energy services companies acquired by Con Edison Solutions and a gas storage company acquired by Con Edison Development, and determined that the goodwill was not impaired. Estimates of future cash flows, projected growth rates, and discount rates inherent in the cash flow estimates for the energy services companies and gas storage company may vary significantly from actual results, which could result in a future impairment of goodwill.
CECONY
Goodwill [Line Items]
Goodwill	Goodwill In 2015 and 2014, Con Edison completed impairment tests for its goodwill of $406 million related to the O&R merger, and determined that it was not impaired. For the impairment test, $245 million and $161 million of the goodwill were allocated to CECONY and O&R, respectively. In 2015 and 2014, Con Edison also completed impairment tests for the goodwill of $23 million related to two energy services companies acquired by Con Edison Solutions and a gas storage company acquired by Con Edison Development, and determined that the goodwill was not impaired. Estimates of future cash flows, projected growth rates, and discount rates inherent in the cash flow estimates for the energy services companies and gas storage company may vary significantly from actual results, which could result in a future impairment of goodwill.

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Income Tax

12 Months Ended

Dec. 31, 2015

Income Tax Examination [Line Items]

Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
State
Current	$38	$59	$151	$48	$66	$111
Deferred	93	61	(70)	82	65	(14)
Federal
Current	(86)	(9)	285	77	158	187
Deferred	569	463	115	372	271	241
Amortization of investment tax credits	(9)	(6)	(5)	(5)	(5)	(5)
Total income tax expense	$605	$568	$476	$574	$555	$520

The tax effects of temporary differences, which gave rise to deferred tax assets and liabilities, are as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Deferred tax liabilities:
Property basis differences	$8,614	$7,510	$7,922	$6,938
Regulatory assets:
Unrecognized pension and other postretirement costs	1,562	1,968	1,490	1,872
Future income tax	947	910	899	863
Environmental remediation costs	365	376	322	333
Deferred storm costs	75	129	45	91
Other regulatory assets	367	347	308	300
Equity investments	295	168	—	—
Total deferred tax liabilities	$12,225	$11,408	$10,986	$10,397
Deferred tax assets:
Accrued pension and other postretirement costs	$982	$1,306	$857	$1,155
Regulatory liabilities	836	615	752	574
Superfund and other environmental costs	308	306	268	264
Asset retirement obligations	97	77	94	75
Loss carryforwards	29	21	—	—
Tax credits carryforward	258	—	1	—
Valuation allowance	(15)	(11)	—	—
Other	362	272	292	203
Total deferred tax assets	2,857	2,586	2,264	2,271
Net deferred tax liabilities	$9,368	$8,822	$8,722	$8,126
Unamortized investment tax credits	169	126	33	37
Net deferred tax liabilities and unamortized investment tax credits	$9,537	$8,948	$8,755	$8,163

In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” which requires that all deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The Companies adopted this new pronouncement for the year ended December 31, 2015 and applied it retrospectively. As a result, Con Edison and CECONY adjusted $128 million and $94 million, respectively, from current deferred tax assets to noncurrent deferred tax income taxes and unamortized investment tax credits on the Companies' consolidated balance sheets at December 31, 2014.

Reconciliation of the difference between income tax expense and the amount computed by applying the prevailing statutory income tax rate to income before income taxes is as follows:



	Con Edison						CECONY
(% of Pre-tax income)	2015		2014		2013		2015		2014		2013
STATUTORY TAX RATE
Federal	35	%	35	%	35	%	35	%	35	%	35	%
Changes in computed taxes resulting from:
State income tax	5		5		4		5		5		5
Cost of removal	(5	)	(5	)	(5	)	(5	)	(5	)	(5	)
Manufacturing deduction	—		—		(1	)	—		—		—
Other	(1	)	(1	)	(2	)	—		(1	)	(1	)
Effective tax rate	34	%	34	%	31	%	35	%	34	%	34	%

In 2015, Con Edison had a federal net operating loss, due primarily to accelerated bonus depreciation. The Company expects to carryback its 2015 net operating loss to 2013 and recover $6 million of 2013 income tax. Con Edison has $258 million in general business tax credits, which if unused will begin to expire in 2032. A deferred tax asset for this tax attribute carryforward was recorded, and no valuation allowance has been provided, as it is more likely than not that the deferred tax asset will be realized. As a result of the extension of bonus depreciation for 2015 and 2016 (see discussion below), Con Edison recorded a full valuation allowance of $4 million in 2015 against its charitable contribution carryforwards of $1 million and $9 million from 2010 and 2011, respectively, that will expire in 2015 and 2016. In addition, an $11 million valuation allowance for New York City income tax purposes has been provided; as it is not more likely than not that the deferred tax asset will be realized.

In 2014, tax legislation was enacted in the State of New York that reduced the corporate franchise tax rate from 7.1 percent to 6.5 percent, beginning January 1, 2016. The application of this legislation decreased Con Edison’s accumulated deferred tax liabilities by $74 million ($69 million for CECONY), decreased Con Edison’s regulatory asset for future income tax by $11 million ($10 million for CECONY) and increased Con Edison’s regulatory liability by $62 million ($59 million for CECONY). The impact of this tax legislation on Con Edison’s effective tax rate was not material, and there was no impact on CECONY’s effective tax rate for the year ended December 31, 2014.

Under the Taxpayer Relief Act of 2012, 50 percent bonus depreciation expired on December 31, 2013. In December 2014, President Obama signed into law the Tax Increase Prevention Act of 2014, which extended bonus depreciation for another year through December 31, 2014. As a result of the extension of bonus depreciation to 2014, Con Edison filed a refund request with the IRS in January 2015 to recover $224 million ($128 million for CECONY) in estimated federal tax payments and received the refund in March 2015.

In December 2015, President Obama signed into law the Protecting Americans from Tax Hikes Act of 2015, which extends bonus depreciation for property acquired and placed in service during 2015 through 2019. The bonus depreciation percentage is 50 percent for property placed in service during 2015, 2016 and 2017 and phases down to 40 percent in 2018, and 30 percent in 2019. As a result of the extension of bonus depreciation to 2015, Con Edison filed a refund request with the IRS in January 2016 to recover $160 million in estimated federal tax payments. In February 2016, Con Edison received a refund of estimated taxes paid in the amount of $160 million ($143 million for CECONY).

Uncertain Tax Positions

Under the accounting rules for income taxes, the Companies are not permitted to recognize the tax benefit attributable to a tax position unless such position is more likely than not to be sustained upon examination by taxing authorities, including resolution of any related appeals and litigation processes, based solely on the technical merits of the position.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits for Con Edison and CECONY follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014		2013
Balance at January 1,	$34	$9	$86	$2		$—	$74
Additions based on tax positions related to the current year	—	—	5	—	—		—
Additions based on tax positions of prior years	1	27	253	—	2		—
Reductions for tax positions of prior years	—	(2)	(86)	—	—		(74)
Reductions from expiration of statute of limitations	(1)	—	—	—	—		—
Settlements	—	—	(249)	—	—		—
Balance at December 31,	$34	$34	$9	$2	$2			$—

As of December 31, 2015, Con Edison reasonably expects to resolve approximately $25 million ($16 million, net of federal taxes) of its uncertainties related to certain tax matters within the next twelve months. Favorable resolution would reduce Con Edison’s effective tax rate. The amount related to CECONY is approximately $2 million ($1 million, net of federal taxes), of which the entire amount, if recognized, would reduce CECONY’s effective tax rate.

The Companies recognize interest on liabilities for uncertain tax positions in interest expense and would recognize penalties, if any, in operating expenses in the Companies’ consolidated income statements. In 2015 and 2014, the Companies recognized an immaterial amount of interest and no penalties for uncertain tax positions in their consolidated income statements. In 2013, Con Edison recognized $121 million of interest expense ($131 million related to the LILO transactions (see “Lease In/Lease Out Transactions” in Note J), less a reduction of $10 million in accrued interest expense primarily associated with repair allowance deductions and reversing other uncertain tax positions in 2013). At December 31, 2015 and 2014, the Companies recognized an immaterial amount of interest and no penalties in their consolidated balance sheets.

At December 31, 2015, the total amount of unrecognized tax benefits that, if recognized, would reduce the Companies’ effective tax rate is $34 million ($22 million, net of federal taxes) with $2 million ($1 million, net of federal taxes) attributable to CECONY.

The federal tax returns for 2012 through 2014 remain open for examinations. State income tax returns remain open for examination in New York for tax years 2006 through 2014 and in New Jersey for tax years 2008 through 2014.

CECONY

Income Tax Examination [Line Items]

Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
State
Current	$38	$59	$151	$48	$66	$111
Deferred	93	61	(70)	82	65	(14)
Federal
Current	(86)	(9)	285	77	158	187
Deferred	569	463	115	372	271	241
Amortization of investment tax credits	(9)	(6)	(5)	(5)	(5)	(5)
Total income tax expense	$605	$568	$476	$574	$555	$520

The tax effects of temporary differences, which gave rise to deferred tax assets and liabilities, are as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Deferred tax liabilities:
Property basis differences	$8,614	$7,510	$7,922	$6,938
Regulatory assets:
Unrecognized pension and other postretirement costs	1,562	1,968	1,490	1,872
Future income tax	947	910	899	863
Environmental remediation costs	365	376	322	333
Deferred storm costs	75	129	45	91
Other regulatory assets	367	347	308	300
Equity investments	295	168	—	—
Total deferred tax liabilities	$12,225	$11,408	$10,986	$10,397
Deferred tax assets:
Accrued pension and other postretirement costs	$982	$1,306	$857	$1,155
Regulatory liabilities	836	615	752	574
Superfund and other environmental costs	308	306	268	264
Asset retirement obligations	97	77	94	75
Loss carryforwards	29	21	—	—
Tax credits carryforward	258	—	1	—
Valuation allowance	(15)	(11)	—	—
Other	362	272	292	203
Total deferred tax assets	2,857	2,586	2,264	2,271
Net deferred tax liabilities	$9,368	$8,822	$8,722	$8,126
Unamortized investment tax credits	169	126	33	37
Net deferred tax liabilities and unamortized investment tax credits	$9,537	$8,948	$8,755	$8,163

Reconciliation of the difference between income tax expense and the amount computed by applying the prevailing statutory income tax rate to income before income taxes is as follows:



	Con Edison						CECONY
(% of Pre-tax income)	2015		2014		2013		2015		2014		2013
STATUTORY TAX RATE
Federal	35	%	35	%	35	%	35	%	35	%	35	%
Changes in computed taxes resulting from:
State income tax	5		5		4		5		5		5
Cost of removal	(5	)	(5	)	(5	)	(5	)	(5	)	(5	)
Manufacturing deduction	—		—		(1	)	—		—		—
Other	(1	)	(1	)	(2	)	—		(1	)	(1	)
Effective tax rate	34	%	34	%	31	%	35	%	34	%	34	%

Uncertain Tax Positions

A reconciliation of the beginning and ending amounts of unrecognized tax benefits for Con Edison and CECONY follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014		2013
Balance at January 1,	$34	$9	$86	$2		$—	$74
Additions based on tax positions related to the current year	—	—	5	—	—		—
Additions based on tax positions of prior years	1	27	253	—	2		—
Reductions for tax positions of prior years	—	(2)	(86)	—	—		(74)
Reductions from expiration of statute of limitations	(1)	—	—	—	—		—
Settlements	—	—	(249)	—	—		—
Balance at December 31,	$34	$34	$9	$2	$2			$—

Stock-Based Compensation

12 Months Ended

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Stock-Based Compensation

The Companies may compensate employees and directors with, among other things, stock options, stock units, restricted stock units and contributions to the stock purchase plan. The Long Term Incentive Plan, which was approved by Con Edison’s shareholders in 2003 (2003 LTIP), and the Long Term Incentive Plan, which was approved by Con Edison’s shareholders in 2013 (2013 LTIP), are collectively referred to herein as the LTIP. The LTIP provides for, among other things, awards to employees of restricted stock units and stock options and, to Con Edison’s non-employee directors, stock units. Existing awards under the 2003 LTIP continue in effect, however no new awards may be issued under the 2003 LTIP. The 2013 LTIP provides for awards for up to five million shares of common stock.

Shares of Con Edison common stock used to satisfy the Companies’ obligations with respect to stock-based compensation may be new (authorized, but unissued) shares, treasury shares or shares purchased in the open market. The shares used during the year ended December 31, 2015 were treasury shares and new shares. The Companies intend to use new shares to fulfill their stock-based compensation obligations for 2016.

The Companies recognized stock-based compensation expense using a fair value measurement method. The following table summarizes stock-based compensation expense recognized by the Companies in the years ended December 31, 2015, 2014 and 2013:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Performance-based restricted stock	$27	$22	$20	$23	$19	$18
Time-based restricted stock	1	2	2	1	2	2
Non-employee director deferred stock compensation	2	2	2	2	2	2
Stock purchase plan	4	3	3	3	3	3
Total	$34	$29	$27	$29	$26	$25
Income tax benefit	$14	$12	$11	$12	$10	$10

Stock Options

The Companies last granted stock options in 2006. The stock options generally vested over a three-year period and have a term of 10 years. Options were granted at an exercise price equal to the fair market value of a common share when the option was granted. The Companies generally recognized compensation expense (based on the fair value of stock option awards) over the vesting period.

The outstanding options are “equity awards” because shares of Con Edison common stock are delivered upon exercise of the options. As equity awards, the fair value of the options is measured at the grant date.

A summary of changes in the status of stock options as of December 31, 2015 is as follows:



	Con Edison		CECONY
	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price
Outstanding at December 31, 2014	229,850	$42.99	191,350	$43.00
Exercised	150,225	42.71	125,575	42.74
Forfeited	500	43.50	—	—
Outstanding at December 31, 2015 (a)	79,125	$43.50	65,775	$43.50

(a) The weighted average remaining contractual life is one year for all outstanding options as of December 31, 2015.

The following table summarizes information about stock options for the years ended December 31, 2015 and 2014:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Aggregate intrinsic value (a)
Options outstanding	$2	$5	$1	$4
Options exercised	3	4	3	3
Cash received by Con Edison for payment of exercise price	6	11	5	8

(a) Aggregate intrinsic value represents the changes in the fair value of all outstanding options from their grant dates to December 31 of the years presented above.

The income tax benefit Con Edison realized from stock options exercised in the years ended December 31, 2015, 2014 and 2013 was $1 million, $1 million and $10 million, respectively.

Restricted Stock and Stock Units

Restricted stock and stock unit awards under the LTIP have been made as follows: (i) awards that provide for adjustment of the number of units (performance-restricted stock units or Performance RSUs) to certain officers and employees; (ii) time-based awards to certain employees; and (iii) awards to non-employee directors. Restricted stock and stock units awarded represents the right to receive, upon vesting, shares of Con Edison common stock, or, except for units awarded under the directors’ plan, the cash value of shares or a combination thereof.

The number of units in each annual Performance RSU award is subject to adjustment as follows: (i) 50 percent of the units awarded will be multiplied by a factor that may range from 0 to 200 percent, based on Con Edison’s total shareholder return relative to a specified peer group during a specified performance period (the TSR portion); and (ii) 50 percent of the units awarded will be multiplied by a factor that may range from 0 to 120 percent for management employees and from 0 to 200 percent, based on the Companies’ annual incentive plans or, for certain executive officers, actual performance as compared to certain performance measures during a specified performance period (the non-TSR portion). Performance RSU awards generally vest upon completion of the performance period.

Performance against the established targets is recomputed each reporting period as of the earlier of the reporting date and the vesting date. The TSR portion applies a Monte Carlo simulation model, and the non-TSR portion is the product of the market price at the end of the period and the average non-TSR determination over the vesting period. Performance RSUs are “liability awards” because each Performance RSU represents the right to receive, upon vesting, one share of Con Edison common stock, the cash value of a share or a combination thereof. As such, changes in the fair value of the Performance RSUs are reflected in net income. The assumptions used to calculate the fair value of the awards were as follows:



	2015	2014	2013
Risk-free interest rate (a)	0.64% - 3.28%	0.23% - 3.07%	0.13% - 5.17%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	15.82%	13.14%	13.52%


(a)	The risk-free rate is based on the U.S. Treasury zero-coupon yield curve on the date of grant.


(b)	The expected term of the Performance RSUs equals the vesting period. The Companies do not expect significant forfeitures to occur.


(c)	The expected volatility is calculated using daily closing stock prices over a period of three years, which approximates the expected term of the awards.

A summary of changes in the status of the Performance RSUs’ TSR and non-TSR portions during the year ended December 31, 2015 is as follows:



	Con Edison			CECONY
		Weighted Average Grant Date Fair Value (a)			Weighted Average Grant Date Fair Value (a)
	Units	TSR Portion (b)	Non-TSR Portion (c)	Units	TSR Portion (b)	Non-TSR Portion (c)
Non-vested at December 31, 2014	1,100,607	$42.33	$56.61	880,523	$42.58	$56.70
Granted	363,900	57.67	63.22	288,669	57.22	63.12
Vested	(327,536)	49.45	58.84	(266,683)	49.34	58.83
Forfeited	(58,632)	43.84	58.25	(49,252)	43.54	58.14
Non-vested at December 31, 2015	1,078,339	$45.26	$58.08	853,257	$45.37	$58.12


(a)	The TSR and non-TSR Portions each account for 50 percent of the awards’ value.


(b)	Fair value is determined using the Monte Carlo simulation described above. Weighted average grant date fair value does not reflect any accrual or payment of dividends prior to vesting.


(c)	Fair value is determined using the market price of one share of Con Edison common stock on the grant date. The market price has not been discounted to reflect that dividends do not accrue and are not payable on Performance RSUs until vesting.

The total expense to be recognized by Con Edison in future periods for unvested Performance RSUs outstanding at December 31, 2015 is $29 million, including $23 million for CECONY, and is expected to be recognized over a weighted average period of one year for both Con Edison and CECONY.

In accordance with the accounting rules for stock compensation, for time-based awards, the Companies have accrued a liability based on the market value of a common share on the grant date and are recognizing compensation expense over the vesting period. The vesting period for awards is three years and is based on the employee’s continuous service to Con Edison. Prior to vesting, the awards are subject to forfeiture in whole or in part under certain circumstances. The awards are “liability awards” because each restricted stock unit represents the right to receive, upon vesting, one share of Con Edison common stock, the cash value of a share or a combination thereof. As such, prior to vesting, changes in the fair value of the units are reflected in net income.

A summary of changes in the status of time-based awards during the year ended December 31, 2015 is as follows:



	Con Edison		CECONY
	Units	Weighted Average Grant Date Fair Value	Units	Weighted Average Grant Date Fair Value
Non-vested at December 31, 2014	65,423	$57.65	62,173	$57.64
Granted	23,000	61.00	21,800	61.00
Vested	(20,773)	58.42	(19,773)	58.42
Forfeited	(2,670)	58.35	(2,570)	58.39
Non-vested at December 31, 2015	64,980	$58.56	61,630	$58.55

The total expense to be recognized by Con Edison in future periods for unvested time-based awards outstanding at December 31, 2015 for Con Edison and CECONY was $2 million and is expected to be recognized over a weighted average period of one year.

Under the LTIP, each non-employee director receives stock units, which are deferred until the director’s separation from service or another date specified by the director. Each director may also elect to defer all or a portion of their cash compensation into additional stock units, which are deferred until the director’s termination of service or another date specified by the director. Non-employee directors’ stock units issued under the LTIP are considered “equity awards,” because they may only be settled in shares. Directors immediately vest in units issued to them. The fair value of the units is determined using the closing price of Con Edison’s common stock on the business day immediately preceding the date of issue. In the year ended December 31, 2015, approximately 30,724 units were issued at a weighted average grant date price of $61.31.

Stock Purchase Plan

The Stock Purchase Plan, which was approved by shareholders in 2004 and 2014, provides for the Companies to contribute up to $1 for each $9 invested by their directors, officers or employees to purchase Con Edison common stock under the plan. Eligible participants may invest up to $25,000 during any calendar year (subject to an additional limitation for officers and employees of not more than 20 percent of their pay). Dividends paid on shares held under the plan are reinvested in additional shares unless otherwise directed by the participant.

Participants in the plan immediately vest in shares purchased by them under the plan. The fair value of the shares of Con Edison common stock purchased under the plan was calculated using the average of the high and low composite sale prices at which shares were traded at the New York Stock Exchange on the trading day immediately preceding such purchase dates. During 2015, 2014 and 2013, 761,784, 708,276 and 864,281 shares were purchased under the Stock Purchase Plan at a weighted average price of $62.75, $56.23 and $57.24 per share, respectively.

CECONY

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Stock-Based Compensation



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Performance-based restricted stock	$27	$22	$20	$23	$19	$18
Time-based restricted stock	1	2	2	1	2	2
Non-employee director deferred stock compensation	2	2	2	2	2	2
Stock purchase plan	4	3	3	3	3	3
Total	$34	$29	$27	$29	$26	$25
Income tax benefit	$14	$12	$11	$12	$10	$10

Stock Options

A summary of changes in the status of stock options as of December 31, 2015 is as follows:



	Con Edison		CECONY
	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price
Outstanding at December 31, 2014	229,850	$42.99	191,350	$43.00
Exercised	150,225	42.71	125,575	42.74
Forfeited	500	43.50	—	—
Outstanding at December 31, 2015 (a)	79,125	$43.50	65,775	$43.50

(a) The weighted average remaining contractual life is one year for all outstanding options as of December 31, 2015.

The following table summarizes information about stock options for the years ended December 31, 2015 and 2014:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Aggregate intrinsic value (a)
Options outstanding	$2	$5	$1	$4
Options exercised	3	4	3	3
Cash received by Con Edison for payment of exercise price	6	11	5	8

(a) Aggregate intrinsic value represents the changes in the fair value of all outstanding options from their grant dates to December 31 of the years presented above.

The income tax benefit Con Edison realized from stock options exercised in the years ended December 31, 2015, 2014 and 2013 was $1 million, $1 million and $10 million, respectively.

Restricted Stock and Stock Units



	2015	2014	2013
Risk-free interest rate (a)	0.64% - 3.28%	0.23% - 3.07%	0.13% - 5.17%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	15.82%	13.14%	13.52%


(a)	The risk-free rate is based on the U.S. Treasury zero-coupon yield curve on the date of grant.


(b)	The expected term of the Performance RSUs equals the vesting period. The Companies do not expect significant forfeitures to occur.


(c)	The expected volatility is calculated using daily closing stock prices over a period of three years, which approximates the expected term of the awards.

A summary of changes in the status of the Performance RSUs’ TSR and non-TSR portions during the year ended December 31, 2015 is as follows:



	Con Edison			CECONY
		Weighted Average Grant Date Fair Value (a)			Weighted Average Grant Date Fair Value (a)
	Units	TSR Portion (b)	Non-TSR Portion (c)	Units	TSR Portion (b)	Non-TSR Portion (c)
Non-vested at December 31, 2014	1,100,607	$42.33	$56.61	880,523	$42.58	$56.70
Granted	363,900	57.67	63.22	288,669	57.22	63.12
Vested	(327,536)	49.45	58.84	(266,683)	49.34	58.83
Forfeited	(58,632)	43.84	58.25	(49,252)	43.54	58.14
Non-vested at December 31, 2015	1,078,339	$45.26	$58.08	853,257	$45.37	$58.12


(a)	The TSR and non-TSR Portions each account for 50 percent of the awards’ value.


(b)	Fair value is determined using the Monte Carlo simulation described above. Weighted average grant date fair value does not reflect any accrual or payment of dividends prior to vesting.


(c)	Fair value is determined using the market price of one share of Con Edison common stock on the grant date. The market price has not been discounted to reflect that dividends do not accrue and are not payable on Performance RSUs until vesting.

A summary of changes in the status of time-based awards during the year ended December 31, 2015 is as follows:



	Con Edison		CECONY
	Units	Weighted Average Grant Date Fair Value	Units	Weighted Average Grant Date Fair Value
Non-vested at December 31, 2014	65,423	$57.65	62,173	$57.64
Granted	23,000	61.00	21,800	61.00
Vested	(20,773)	58.42	(19,773)	58.42
Forfeited	(2,670)	58.35	(2,570)	58.39
Non-vested at December 31, 2015	64,980	$58.56	61,630	$58.55

Stock Purchase Plan

Financial Information by Business Segment

12 Months Ended

Dec. 31, 2015

Segment Reporting Information [Line Items]

Financial Information by Business Segment

The business segments of each of the Companies, which are its operating segments, were determined based on management’s reporting and decision-making requirements in accordance with the accounting rules for segment reporting.

Con Edison’s principal business segments are CECONY’s regulated utility activities, O&R’s regulated utility activities and Con Edison’s competitive energy businesses. CECONY’s principal business segments are its regulated electric, gas and steam utility activities.

All revenues of these business segments are from customers located in the United States of America. Also, all assets of the business segments are located in the United States of America. The accounting policies of the segments are the same as those described in Note A.

Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided.

The financial data for the business segments are as follows:



As of and for the Year Ended December 31, 2015 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)	Construction expenditures
CECONY
Electric	$8,172	$18		$820	$1,798	$447	$447	$30,603	$1,658
Gas	1,527	6		142	356	96	100	6,974	671
Steam	629	86		78	93	41	41	2,653	106
Consolidation adjustments	—	(110)		—	—	—	—	—	—
Total CECONY	$10,328		$—	$1,040	$2,247	$584	$588	$40,230	$2,435
O&R
Electric	$663		$—	$50	$103	$23	$31	$2,140	$114
Gas	182	—		18	18	12	2	579	46
Other (b)	—	—		—	—	—	—	—	—
Total O&R	$845		$—	$68	$121	$35	$33	$2,719	$160
Competitive energy businesses	$1,383	$(2)		$22	$58	$11	$22	$1,680	$823
Other (c)	(2)	2		—	1	23	1	1,013	—
Total Con Edison	$12,554		$—	$1,130	$2,427	$653	$644	$45,642	$3,418



As of and for the Year Ended December 31, 2014 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)(d)	Construction expenditures
CECONY
Electric	$8,437	$16		$781	$1,712	$412	$425	$30,295	$1,500
Gas	1,721	6		132	314	89	88	6,478	549
Steam	628	84		78	113	36	49	2,670	83
Consolidation adjustments	—	(106)		—	—	—	—	—	—
Total CECONY	$10,786		$—	$991	$2,139	$537	$562	$39,443	$2,132
O&R
Electric	$680		$—	$46	$103	$24	$29	$2,023	$105
Gas	212	—		15	25	10	6	786	37
Other (b)	—	—		—	—	1	—	1	—
Total O&R	$892		$—	$61	$128	$35	$35	$2,810	$142
Competitive energy businesses	$1,244	$(10)		$19	$(60)	$(8)	$(8)	$1,013	$447
Other (c)	(3)	10		—	2	27	—	805	—
Total Con Edison	$12,919		$—	$1,071	$2,209	$591	$589	$44,071	$2,721



As of and for the Year Ended December 31, 2013 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)(d)	Construction expenditures
CECONY
Electric	$8,131	$16		$749	$1,595	$402	$380	$27,547	$1,471
Gas	1,616	5		130	362	83	112	5,977	536
Steam	683	82		67	103	36	39	2,571	128
Consolidation adjustments	—	(103)		—	—	—	—	—	—
Total CECONY	$10,430		$—	$946	$2,060	$521	$531	$36,095	$2,135
O&R
Electric	$628		$—	$41	$87	$25	$13	$1,882	$98
Gas	205	—		15	33	11	7	640	37
Other (b)	—	—		—	—	1	—	2	—
Total O&R	$833		$—	$56	$120	$37	$20	$2,524	$135
Competitive energy businesses	$1,096	$5		$23	$63	$135	$(41)	$1,305	$378
Other (c)	(5)	(5)		(1)	1	26	(6)	527	—
Total Con Edison	$12,354		$—	$1,024	$2,244	$719	$504	$40,451	$2,648


(a)	For Con Edison, the income tax expense on non-operating income was $40 million, $21 million and $28 million in 2015, 2014 and 2013, respectively. For CECONY, the income tax expense on non-operating income was $14 million, $7 million and $11 million in 2015, 2014 and 2013, respectively.


(b)	Includes amounts related to the RECO securitization.


(c)	Parent company, consolidation adjustments and Con Edison Transmission. Other does not represent a business segment.


(d)	Reflects $237 million and $196 million in 2014 and 2013, respectively, related to the adoption of ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” See Notes C and L.

CECONY

Segment Reporting Information [Line Items]

Financial Information by Business Segment

Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided.

The financial data for the business segments are as follows:



As of and for the Year Ended December 31, 2015 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)	Construction expenditures
CECONY
Electric	$8,172	$18		$820	$1,798	$447	$447	$30,603	$1,658
Gas	1,527	6		142	356	96	100	6,974	671
Steam	629	86		78	93	41	41	2,653	106
Consolidation adjustments	—	(110)		—	—	—	—	—	—
Total CECONY	$10,328		$—	$1,040	$2,247	$584	$588	$40,230	$2,435
O&R
Electric	$663		$—	$50	$103	$23	$31	$2,140	$114
Gas	182	—		18	18	12	2	579	46
Other (b)	—	—		—	—	—	—	—	—
Total O&R	$845		$—	$68	$121	$35	$33	$2,719	$160
Competitive energy businesses	$1,383	$(2)		$22	$58	$11	$22	$1,680	$823
Other (c)	(2)	2		—	1	23	1	1,013	—
Total Con Edison	$12,554		$—	$1,130	$2,427	$653	$644	$45,642	$3,418



As of and for the Year Ended December 31, 2014 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)(d)	Construction expenditures
CECONY
Electric	$8,437	$16		$781	$1,712	$412	$425	$30,295	$1,500
Gas	1,721	6		132	314	89	88	6,478	549
Steam	628	84		78	113	36	49	2,670	83
Consolidation adjustments	—	(106)		—	—	—	—	—	—
Total CECONY	$10,786		$—	$991	$2,139	$537	$562	$39,443	$2,132
O&R
Electric	$680		$—	$46	$103	$24	$29	$2,023	$105
Gas	212	—		15	25	10	6	786	37
Other (b)	—	—		—	—	1	—	1	—
Total O&R	$892		$—	$61	$128	$35	$35	$2,810	$142
Competitive energy businesses	$1,244	$(10)		$19	$(60)	$(8)	$(8)	$1,013	$447
Other (c)	(3)	10		—	2	27	—	805	—
Total Con Edison	$12,919		$—	$1,071	$2,209	$591	$589	$44,071	$2,721



As of and for the Year Ended December 31, 2013 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)(d)	Construction expenditures
CECONY
Electric	$8,131	$16		$749	$1,595	$402	$380	$27,547	$1,471
Gas	1,616	5		130	362	83	112	5,977	536
Steam	683	82		67	103	36	39	2,571	128
Consolidation adjustments	—	(103)		—	—	—	—	—	—
Total CECONY	$10,430		$—	$946	$2,060	$521	$531	$36,095	$2,135
O&R
Electric	$628		$—	$41	$87	$25	$13	$1,882	$98
Gas	205	—		15	33	11	7	640	37
Other (b)	—	—		—	—	1	—	2	—
Total O&R	$833		$—	$56	$120	$37	$20	$2,524	$135
Competitive energy businesses	$1,096	$5		$23	$63	$135	$(41)	$1,305	$378
Other (c)	(5)	(5)		(1)	1	26	(6)	527	—
Total Con Edison	$12,354		$—	$1,024	$2,244	$719	$504	$40,451	$2,648


(a)	For Con Edison, the income tax expense on non-operating income was $40 million, $21 million and $28 million in 2015, 2014 and 2013, respectively. For CECONY, the income tax expense on non-operating income was $14 million, $7 million and $11 million in 2015, 2014 and 2013, respectively.


(b)	Includes amounts related to the RECO securitization.


(c)	Parent company, consolidation adjustments and Con Edison Transmission. Other does not represent a business segment.


(d)	Reflects $237 million and $196 million in 2014 and 2013, respectively, related to the adoption of ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” See Notes C and L.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Publisher FASB
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-Name Accounting Standards Codification
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2015

Derivative [Line Items]

Derivative Instruments and Hedging Activities

Con Edison’s subsidiaries hedge market price fluctuations associated with physical purchases and sales of electricity, natural gas, steam and, to a lesser extent, refined fuels by using derivative instruments including futures, forwards, basis swaps, options, transmission congestion contracts and financial transmission rights contracts. Derivatives are recognized on the balance sheet at fair value (see Note P), unless an exception is available under the accounting rules for derivatives and hedging. Qualifying derivative contracts that have been designated as normal purchases or normal sales contracts are not reported at fair value under the accounting rules.

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2015 and 2014 were:



(Millions of Dollars)	2015				2014
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$59	$(41)	$18	(b)	$111	$(67)	$44	(b)
Current - assets held for sale (c)	51	(50)	1		—	—	—
Noncurrent	57	(54)	3		34	(23)	11
Noncurrent - assets held for sale (c)	15	(15)	—		—	—	—
Total fair value of derivative assets	$182	$(160)	$22		$145	$(90)	$55
Fair value of derivative liabilities
Current	$(144)	$78	$(66)		$(242)	$139	$(103)
Current - liabilities held for sale (c)	(115)	50	(65)		—	—	—
Noncurrent	(102)	63	(39)		(66)	91	25
Noncurrent - liabilities held for sale (c)	(28)	15	(13)		—	—	—
Total fair value of derivative liabilities	$(389)	$206	$(183)		$(308)	$230	$(78)
Net fair value derivative assets/(liabilities)	$(207)	$46	$(161)	(b)	$(163)	$140	$(23)	(b)
CECONY
Fair value of derivative assets
Current	$40	$(32)	$8	(b)	$26	$(15)	$11	(b)
Noncurrent	48	(47)	1		22	(20)	2
Total fair value of derivative assets	$88	$(79)	$9		$48	$(35)	$13
Fair value of derivative liabilities
Current	$(121)	$71	$(50)		$(96)	$48	$(48)
Noncurrent	(92)	56	(36)		(42)	32	(10)
Total fair value of derivative liabilities	$(213)	$127	$(86)		$(138)	$80	$(58)
Net fair value derivative assets/(liabilities)	$(125)	$48	$(77)	(b)	$(90)	$45	$(45)	(b)

(a)

Derivative instruments and collateral were offset on the consolidated balance sheet as applicable under the accounting rules. The Companies enter into master agreements for their commodity derivatives. These agreements typically provide offset in the event of contract termination. In such case, generally the non-defaulting party’s payable will be offset by the defaulting party’s payable. The non-defaulting party will customarily notify the defaulting party within a specific time period and come to an agreement on the early termination amount.

(b)

At December 31, 2015 and 2014, margin deposits for Con Edison ($26 million and $27 million, respectively) and CECONY ($26 million and $25 million, respectively) were classified as derivative assets on the consolidated balance sheet, but not included in the table. Margin is collateral, typically cash, that the holder of a derivative instrument is required to deposit in order to transact on an exchange and to cover its potential losses with its broker or the exchange.


(c)	Amounts represent derivative assets and liabilities included in assets and liabilities held for sale on the consolidated balance sheet (see Note U).

The Utilities generally recover their prudently incurred fuel, purchased power and gas costs, including hedging gains and losses, in accordance with rate provisions approved by the applicable state utility regulators. See “Recoverable Energy Costs” in Note A. In accordance with the accounting rules for regulated operations, the Utilities record a regulatory asset or liability to defer recognition of unrealized gains and losses on their electric and gas derivatives. As gains and losses are realized in future periods, they will be recognized as purchased power, gas and fuel costs in the Companies’ consolidated income statements. Con Edison’s competitive energy businesses record realized and unrealized gains and losses on their derivative contracts in purchased power, gas purchased for resale and non-utility revenue in the reporting period in which they occur. Management believes that these derivative instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices.

The following table presents the realized and unrealized gains or losses on commodity derivatives that have been deferred or recognized in earnings for the years ended December 31, 2015 and 2014:



		Con Edison				CECONY
(Millions of Dollars)	Balance Sheet Location	2015		2014		2015			2014
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$1		$(10)		$2			$(7)
Noncurrent	Deferred derivative gains	1		1		—			1
Total deferred gains/(losses)		$2		$(9)		$2			$(6)
Current	Deferred derivative losses	$(16)		$(75)		$(11)			$(70)
Current	Recoverable energy costs	(136)		36		(127)			26
Noncurrent	Deferred derivative losses	(25)		(17)		(23)			(17)
Total deferred gains/(losses)		$(177)		$(56)		$(161)			$(61)
Net deferred gains/(losses)		$(175)		$(65)		$(159)			$(67)
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Purchased power expense	$(109)	(a)	$(37)	(b)		$—			$—
	Gas purchased for resale	(106)		(115)		—			—
	Non-utility revenue	30	(a)	29	(b)	—			—
	Other operations and maintenance expense	(1)	(c)	—		(1)		(c)	—
Total pre-tax gain/(loss) recognized in income		$(186)		$(123)		$(1)				$—


(a)	For the year ended December 31, 2015, Con Edison recorded unrealized pre-tax gains and losses in non-utility operating revenue ($1 million gain) and purchased power expense ($1 million loss).


(b)	For the year ended December 31, 2014, Con Edison recorded unrealized pre-tax gains and losses in non-utility operating revenue ($4 million gain) and purchased power expense ($132 million loss).


(c)	For the year ended December 31, 2015, Con Edison and CECONY recorded an unrealized loss in other operations and maintenance expense ($1 million).

The following table presents the hedged volume of Con Edison’s and CECONY’s derivative transactions at December 31, 2015:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison (c)	37,036,264	21,174	50,052,794	3,696,000
CECONY	18,742,050	12,000	47,540,000	3,696,000


(a)	Volumes are reported net of long and short positions, except natural gas collars where the volumes of long positions are reported.


(b)	Excludes electric congestion and gas basis swap contracts which are associated with electric and gas contracts and hedged volumes.


(c)	Includes 16,381,544 MWh for electric energy, 7,262 MW for capacity and 580,362 Dt for natural gas derivative transactions that are held for sale.

The Companies are exposed to credit risk related to transactions entered into primarily for the various energy supply and hedging activities by the Utilities and the competitive energy businesses. Credit risk relates to the loss that may result from a counterparty’s nonperformance. The Companies use credit policies to manage this risk, including an established credit approval process, monitoring of counterparty limits, netting provisions within agreements, collateral or prepayment arrangements, credit insurance and credit default swaps. The Companies measure credit risk exposure as the replacement cost for open energy commodity and derivative positions plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses where the Companies have a legally enforceable right to offset.

At December 31, 2015, Con Edison and CECONY had $212 million and $26 million of credit exposure in connection with energy supply and hedging activities, net of collateral, respectively. Con Edison’s net credit exposure consisted of $146 million with commodity exchange brokers, $50 million with independent system operators, $8 million with investment-grade counterparties and $8 million with non-investment grade/non-rated counterparties. CECONY’s net credit exposure was with commodity exchange brokers.

The collateral requirements associated with, and settlement of, derivative transactions are included in net cash flows from operating activities in the Companies’ consolidated statement of cash flows. Most derivative instrument contracts contain provisions that may require a party to provide collateral on its derivative instruments that are in a net liability position. The amount of collateral to be provided will depend on the fair value of the derivative instruments and the party’s credit ratings.

The following table presents the aggregate fair value of the Companies’ derivative instruments with credit-risk-related contingent features that are in a net liability position, the collateral posted for such positions and the additional collateral that would have been required to be posted had the lowest applicable credit rating been reduced one level and to below investment grade at December 31, 2015:



(Millions of Dollars)	Con Edison (a)	CECONY (a)
Aggregate fair value – net liabilities	$106	$81
Collateral posted	18	17
Additional collateral (b) (downgrade one level from current ratings)	9	6
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	142	104

(a)

Non-derivative transactions for the purchase and sale of electricity and gas and qualifying derivative instruments, which have been designated as normal purchases or normal sales, are excluded from the table. These transactions primarily include purchases of electricity from independent system operators. In the event the Utilities and the competitive energy businesses were no longer extended unsecured credit for such purchases, the Companies would be required to post additional collateral of $16 million at December 31, 2015. For certain other such non-derivative transactions, the Companies could be required to post collateral under certain circumstances, including in the event counterparties had reasonable grounds for insecurity.

(b)

The Companies measure the collateral requirements by taking into consideration the fair value amounts of derivative instruments that contain credit-risk-related contingent features that are in a net liabilities position plus amounts owed to counterparties for settled transactions and amounts required by counterparties for minimum financial security. The fair value amounts represent unrealized losses, net of any unrealized gains where the Companies have a legally enforceable right to offset.


(c)	Derivative instruments that are net assets have been excluded from the table. At December 31, 2015, if Con Edison had been downgraded to below investment grade, it would have been required to post additional collateral for such derivative instruments of $6 million.

CECONY

Derivative [Line Items]

Derivative Instruments and Hedging Activities

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2015 and 2014 were:



(Millions of Dollars)	2015				2014
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$59	$(41)	$18	(b)	$111	$(67)	$44	(b)
Current - assets held for sale (c)	51	(50)	1		—	—	—
Noncurrent	57	(54)	3		34	(23)	11
Noncurrent - assets held for sale (c)	15	(15)	—		—	—	—
Total fair value of derivative assets	$182	$(160)	$22		$145	$(90)	$55
Fair value of derivative liabilities
Current	$(144)	$78	$(66)		$(242)	$139	$(103)
Current - liabilities held for sale (c)	(115)	50	(65)		—	—	—
Noncurrent	(102)	63	(39)		(66)	91	25
Noncurrent - liabilities held for sale (c)	(28)	15	(13)		—	—	—
Total fair value of derivative liabilities	$(389)	$206	$(183)		$(308)	$230	$(78)
Net fair value derivative assets/(liabilities)	$(207)	$46	$(161)	(b)	$(163)	$140	$(23)	(b)
CECONY
Fair value of derivative assets
Current	$40	$(32)	$8	(b)	$26	$(15)	$11	(b)
Noncurrent	48	(47)	1		22	(20)	2
Total fair value of derivative assets	$88	$(79)	$9		$48	$(35)	$13
Fair value of derivative liabilities
Current	$(121)	$71	$(50)		$(96)	$48	$(48)
Noncurrent	(92)	56	(36)		(42)	32	(10)
Total fair value of derivative liabilities	$(213)	$127	$(86)		$(138)	$80	$(58)
Net fair value derivative assets/(liabilities)	$(125)	$48	$(77)	(b)	$(90)	$45	$(45)	(b)

(a)

(b)


(c)	Amounts represent derivative assets and liabilities included in assets and liabilities held for sale on the consolidated balance sheet (see Note U).

The following table presents the realized and unrealized gains or losses on commodity derivatives that have been deferred or recognized in earnings for the years ended December 31, 2015 and 2014:



		Con Edison				CECONY
(Millions of Dollars)	Balance Sheet Location	2015		2014		2015			2014
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$1		$(10)		$2			$(7)
Noncurrent	Deferred derivative gains	1		1		—			1
Total deferred gains/(losses)		$2		$(9)		$2			$(6)
Current	Deferred derivative losses	$(16)		$(75)		$(11)			$(70)
Current	Recoverable energy costs	(136)		36		(127)			26
Noncurrent	Deferred derivative losses	(25)		(17)		(23)			(17)
Total deferred gains/(losses)		$(177)		$(56)		$(161)			$(61)
Net deferred gains/(losses)		$(175)		$(65)		$(159)			$(67)
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Purchased power expense	$(109)	(a)	$(37)	(b)		$—			$—
	Gas purchased for resale	(106)		(115)		—			—
	Non-utility revenue	30	(a)	29	(b)	—			—
	Other operations and maintenance expense	(1)	(c)	—		(1)		(c)	—
Total pre-tax gain/(loss) recognized in income		$(186)		$(123)		$(1)				$—


(a)	For the year ended December 31, 2015, Con Edison recorded unrealized pre-tax gains and losses in non-utility operating revenue ($1 million gain) and purchased power expense ($1 million loss).


(b)	For the year ended December 31, 2014, Con Edison recorded unrealized pre-tax gains and losses in non-utility operating revenue ($4 million gain) and purchased power expense ($132 million loss).


(c)	For the year ended December 31, 2015, Con Edison and CECONY recorded an unrealized loss in other operations and maintenance expense ($1 million).

The following table presents the hedged volume of Con Edison’s and CECONY’s derivative transactions at December 31, 2015:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison (c)	37,036,264	21,174	50,052,794	3,696,000
CECONY	18,742,050	12,000	47,540,000	3,696,000


(a)	Volumes are reported net of long and short positions, except natural gas collars where the volumes of long positions are reported.


(b)	Excludes electric congestion and gas basis swap contracts which are associated with electric and gas contracts and hedged volumes.


(c)	Includes 16,381,544 MWh for electric energy, 7,262 MW for capacity and 580,362 Dt for natural gas derivative transactions that are held for sale.



(Millions of Dollars)	Con Edison (a)	CECONY (a)
Aggregate fair value – net liabilities	$106	$81
Collateral posted	18	17
Additional collateral (b) (downgrade one level from current ratings)	9	6
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	142	104

(a)

(b)


(c)	Derivative instruments that are net assets have been excluded from the table. At December 31, 2015, if Con Edison had been downgraded to below investment grade, it would have been required to post additional collateral for such derivative instruments of $6 million.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Measurements

The accounting rules for fair value measurements and disclosures define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated, or generally unobservable firm inputs. The Companies often make certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. The Companies use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The accounting rules for fair value measurements and disclosures established a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The rules require that assets and liabilities be classified in their entirety based on the level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and their placement within the fair value hierarchy. The Companies classify fair value balances based on the fair value hierarchy defined by the accounting rules for fair value measurements and disclosures as follows:

•

Level 1 – Consists of assets or liabilities whose value is based on unadjusted quoted prices in active markets at the measurement date. An active market is one in which transactions for assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes contracts traded on active exchange markets valued using unadjusted prices quoted directly from the exchange.

•

Level 2 – Consists of assets or liabilities valued using industry standard models and based on prices, other than quoted prices within Level 1, that are either directly or indirectly observable as of the measurement date. The industry standard models consider observable assumptions including time value, volatility factors and current market and contractual prices for the underlying commodities, in addition to other economic measures. This category includes contracts traded on active exchanges or in over-the-counter markets priced with industry standard models.

•

Level 3 – Consists of assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost benefit constraints. This category includes contracts priced using models that are internally developed and contracts placed in illiquid markets. It also includes contracts that expire after the period of time for which quoted prices are available and internal models are used to determine a significant portion of the value.

Assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2015 and 2014 are summarized below.



	2015						2014
(Millions of Dollars)	Level 1	Level 2	Level 3		Netting Adjustment (e)	Total	Level 1	Level 2	Level 3		Netting Adjustment (e)	Total
Con Edison
Derivative assets:
Commodity (a)(b)(c)	$2	$25	$13		$7	$47	$3	$78	$28		$(27)	$82
Commodity held for sale (f)	—	63	1		(63)	1	—	—	—		—	—
Other (a)(b)(d)	185	112	—		—	297	163	116	—		—	279
Total assets	$187	$200	$14		$(56)	$345	$166	$194	$28		$(27)	$361
Derivative liabilities:
Commodity (a)(b)(c)	$16	$153	$1		$(65)	$105	$18	$246	$8		$(194)	$78
Commodity held for sale (f)	1	133	7		(63)	78	—	—	—		—	—
Total liabilities	$17	$286	$8		$(128)	$183	$18	$246	$8		$(194)	$78
CECONY
Derivative assets:
Commodity (a)(b)(c)	$1	$9	$8		$17	$35	$1	$3	$13		$21	$38
Other (a)(b)(d)	171	105	—		—	276	155	106	—		—	261
Total assets	$172	$114	$8		$17	$311	$156	$109	$13		$21	$299
Derivative liabilities:
Commodity (a)(b)(c)	$14	$129		$—	$(57)	$86	$16	$91		$—	$(49)	$58


(a)	The Companies’ policy is to review the fair value hierarchy and recognize transfers into and transfers out of the levels at the end of each reporting period. There were no transfers between levels 1, 2 and 3 for the years ended December 31, 2015 and 2014.

(b)

Level 2 assets and liabilities include investments held in the deferred compensation plan and/or non-qualified retirement plans, exchange-traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1, certain over-the-counter derivative instruments for electricity, refined products and natural gas. Derivative instruments classified as Level 2 are valued using industry standard models that incorporate corroborated observable inputs; such as pricing services or prices from similar instruments that trade in liquid markets, time value and volatility factors.

(c)

The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At December 31, 2015 and 2014, the Companies determined that nonperformance risk would have no material impact on their financial position or results of operations.


(d)	Other assets are comprised of assets such as life insurance contracts within the deferred compensation plan and non-qualified retirement plans.


(e)	Amounts represent the impact of legally-enforceable master netting agreements that allow the Companies to net gain and loss positions and cash collateral held or placed with the same counterparties.


(f)	Amounts represent derivative assets and liabilities included in Assets and Liabilities held for sale on the consolidated balance sheet (see Note U).

The employees in the Companies’ risk management group develop and maintain the Companies’ valuation policies and procedures for, and verify pricing and fair value valuation of, commodity derivatives. Under the Companies’ policies and procedures, multiple independent sources of information are obtained for forward price curves used to value commodity derivatives. Fair value and changes in fair value of commodity derivatives are reported on a monthly basis to the Companies’ risk committees, comprised of officers and employees of the Companies that oversee energy hedging at the Utilities and the competitive energy businesses. The risk management group reports to the Companies’ Vice President and Treasurer.



	Fair Value of Level 3 at December 31, 2015
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(5)	Discounted Cash Flow	Forward energy prices (a)	$18.33-$77.50 per MWh
		Discounted Cash Flow	Forward capacity prices (a)	$1.17-$7.50 per kW-month
Natural Gas	1	Discounted Cash Flow	Forward natural gas prices (a)	$(7.60) - $5.55 per Dt
Transmission Congestion Contracts/Financial Transmission Rights	10	Discounted Cash Flow	Discount to adjust auction prices for inter-zonal forward price curves (b)	40.8%-62.1%
			Discount to adjust auction prices for historical monthly realized settlements (b)	37.5%-82.2%
			Inter-zonal forward price curves adjusted for historical zonal losses (b)	$(6.35)-$5.59 per MWh
Total Con Edison — Commodity	$6
CECONY — Commodity
Transmission Congestion Contracts	$8	Discounted Cash Flow	Discount to adjust auction prices for inter-zonal forward price curves (b)	40.8%-62.1%
			Discount to adjust auction prices for historical monthly realized settlements (b)	37.5%-82.2%


(a)	Generally, increases/(decreases) in this input in isolation would result in a higher/(lower) fair value measurement.


(b)	Generally, increases/(decreases) in this input in isolation would result in a lower/(higher) fair value measurement.

The table listed below provides a reconciliation of the beginning and ending net balances for assets and liabilities measured at fair value for the years ended December 31, 2015 and 2014 and classified as Level 3 in the fair value hierarchy:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Beginning balance as of January 1,	$20	$9	$13	$6
Included in earnings	(20)	30	(6)	2
Included in regulatory assets and liabilities	1	7	—	7
Purchases	11	22	5	16
Settlements	(6)	(48)	(4)	(18)
Ending balance as of December 31,	$6	$20	$8	$13

For the Utilities, realized gains and losses on Level 3 commodity derivative assets and liabilities are reported as part of purchased power, gas and fuel costs. The Utilities generally recover these costs in accordance with rate provisions approved by the applicable state public utilities regulators. See Note A. Unrealized gains and losses for commodity derivatives are generally deferred on the consolidated balance sheet in accordance with the accounting rules for regulated operations.

For the competitive energy businesses, realized and unrealized gains and losses on Level 3 commodity derivative assets and liabilities are reported in non-utility revenues (immaterial for both years) and purchased power costs ($14 million loss and $27 million gain) on the consolidated income statement for the years ended December 31, 2015 and 2014, respectively. The change in fair value relating to Level 3 commodity derivative assets and liabilities held at December 31, 2015 and 2014 is included in non-utility revenues (immaterial for both years) and purchased power costs ($8 million loss and $2 million gain) on the consolidated income statement for the years ended December 31, 2015 and 2014, respectively.

CECONY

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Measurements

•

Assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2015 and 2014 are summarized below.



	2015						2014
(Millions of Dollars)	Level 1	Level 2	Level 3		Netting Adjustment (e)	Total	Level 1	Level 2	Level 3		Netting Adjustment (e)	Total
Con Edison
Derivative assets:
Commodity (a)(b)(c)	$2	$25	$13		$7	$47	$3	$78	$28		$(27)	$82
Commodity held for sale (f)	—	63	1		(63)	1	—	—	—		—	—
Other (a)(b)(d)	185	112	—		—	297	163	116	—		—	279
Total assets	$187	$200	$14		$(56)	$345	$166	$194	$28		$(27)	$361
Derivative liabilities:
Commodity (a)(b)(c)	$16	$153	$1		$(65)	$105	$18	$246	$8		$(194)	$78
Commodity held for sale (f)	1	133	7		(63)	78	—	—	—		—	—
Total liabilities	$17	$286	$8		$(128)	$183	$18	$246	$8		$(194)	$78
CECONY
Derivative assets:
Commodity (a)(b)(c)	$1	$9	$8		$17	$35	$1	$3	$13		$21	$38
Other (a)(b)(d)	171	105	—		—	276	155	106	—		—	261
Total assets	$172	$114	$8		$17	$311	$156	$109	$13		$21	$299
Derivative liabilities:
Commodity (a)(b)(c)	$14	$129		$—	$(57)	$86	$16	$91		$—	$(49)	$58


(a)	The Companies’ policy is to review the fair value hierarchy and recognize transfers into and transfers out of the levels at the end of each reporting period. There were no transfers between levels 1, 2 and 3 for the years ended December 31, 2015 and 2014.

(b)

(c)


(d)	Other assets are comprised of assets such as life insurance contracts within the deferred compensation plan and non-qualified retirement plans.


(e)	Amounts represent the impact of legally-enforceable master netting agreements that allow the Companies to net gain and loss positions and cash collateral held or placed with the same counterparties.


(f)	Amounts represent derivative assets and liabilities included in Assets and Liabilities held for sale on the consolidated balance sheet (see Note U).



	Fair Value of Level 3 at December 31, 2015
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(5)	Discounted Cash Flow	Forward energy prices (a)	$18.33-$77.50 per MWh
		Discounted Cash Flow	Forward capacity prices (a)	$1.17-$7.50 per kW-month
Natural Gas	1	Discounted Cash Flow	Forward natural gas prices (a)	$(7.60) - $5.55 per Dt
Transmission Congestion Contracts/Financial Transmission Rights	10	Discounted Cash Flow	Discount to adjust auction prices for inter-zonal forward price curves (b)	40.8%-62.1%
			Discount to adjust auction prices for historical monthly realized settlements (b)	37.5%-82.2%
			Inter-zonal forward price curves adjusted for historical zonal losses (b)	$(6.35)-$5.59 per MWh
Total Con Edison — Commodity	$6
CECONY — Commodity
Transmission Congestion Contracts	$8	Discounted Cash Flow	Discount to adjust auction prices for inter-zonal forward price curves (b)	40.8%-62.1%
			Discount to adjust auction prices for historical monthly realized settlements (b)	37.5%-82.2%


(a)	Generally, increases/(decreases) in this input in isolation would result in a higher/(lower) fair value measurement.


(b)	Generally, increases/(decreases) in this input in isolation would result in a lower/(higher) fair value measurement.



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Beginning balance as of January 1,	$20	$9	$13	$6
Included in earnings	(20)	30	(6)	2
Included in regulatory assets and liabilities	1	7	—	7
Purchases	11	22	5	16
Settlements	(6)	(48)	(4)	(18)
Ending balance as of December 31,	$6	$20	$8	$13

Variable Interest Entities

12 Months Ended

Dec. 31, 2015

Variable Interest Entities

The accounting rules for consolidation address the consolidation of a variable interest entity (VIE) by a business enterprise that is the primary beneficiary. A VIE is an entity that does not have a sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary is the business enterprise that has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and either absorbs a significant amount of the VIE’s losses or has the right to receive benefits that could be significant to the VIE.

Con Edison enters into arrangements including leases, partnerships and electricity purchase agreements, with various entities. As a result of these arrangements, Con Edison retains or may retain a variable interest in these entities.

CECONY

CECONY has a variable interest in a non-consolidated VIE, Astoria Energy, LLC (Astoria Energy), with which CECONY has entered into a long-term electricity purchase agreement. CECONY is not the primary beneficiary of this VIE since CECONY does not have the power to direct activities that CECONY believes most significantly impact the economic performance of Astoria Energy. In particular, CECONY has not invested in, or guaranteed the indebtedness of, Astoria Energy and CECONY does not operate or maintain Astoria Energy’s generating facilities. CECONY also has long-term electricity purchase agreements with the following two potential VIEs: Cogen Technologies Linden Venture, LP and Brooklyn Navy Yard Cogeneration Partners, LP. In 2015, requests were made of these counterparties for information necessary to determine whether the entity was a VIE and whether CECONY is the primary beneficiary; however, the information was not made available. See Note I for information on these electricity purchase agreements, the payments pursuant to which constitute CECONY's maximum exposure to loss with respect to the potential VIEs.

Con Edison Development

In 2015, Con Edison Development purchased a 50 percent membership interest in Panoche Holdings, LLC (Panoche Valley). As a result, Con Edison has a variable interest in Panoche Valley, which is a non-consolidated entity. Panoche Valley owns a project company that is developing a 247 MW (AC) solar electric production project in California. Electricity generated by the project is to be sold to the Southern California Edison Company pursuant to a long-term power purchase agreement. Con Edison is not the primary beneficiary since the power to direct the activities that most significantly impact the economics of Panoche Valley is shared equally between Con Edison Development and a third party. At December 31, 2015, Con Edison’s consolidated balance sheet includes $37 million in investments and $77 million representing a note receivable related to Panoche Valley, which assessed in accordance with the accounting rules for variable interest entities, is Con Edison’s current maximum exposure to loss in the entity.

Con Edison has a variable interest in CED California Holdings Financing I, LLC (California Solar), which is no longer a consolidated entity. Con Edison Development sold 50 percent of its membership interest in California Solar which was previously a wholly-owned subsidiary in May 2014. California Solar owns project companies that operate 110 MW (AC) of solar electric production projects in California. Electricity generated by the projects is sold to Pacific Gas and Electric Company pursuant to long-term power purchase agreements. Subsequent to the sale, Con Edison Development’s remaining 50 percent interest in California Solar is accounted for under the equity method.

As a result of the sale, Con Edison Development received net proceeds of $108 million and recognized a pre-tax gain on the sale of $45 million ($26 million, net of tax). The following table summarizes the sale and resultant deconsolidation on the transaction date:



(Millions of Dollars)
Proceeds from sale, net of transaction costs of $1	$108
Non-utility property, less accumulated depreciation	(341)
Other assets, including working capital	(31)
Long-term debt, including current portion	217
Other liabilities	9
Gain on sale of solar electric production projects	(45)
Equity method investment upon deconsolidation	$(83)

Con Edison has a variable interest in OCI Solar San Antonio 4 LLC (Texas Solar 4), which is a consolidated entity in which Con Edison Development purchased an 80 percent membership interest in 2014 for $49 million. Con Edison is the primary beneficiary since the power to direct the activities that most significantly impact the economics of Texas Solar 4 is held by Con Edison Development. Texas Solar 4 owns a project company that developed a 40 MW (AC) solar electric production project in Texas. Electricity generated by the project is sold to the City of San Antonio pursuant to a long-term power purchase agreement. At December 31, 2015 and 2014, Con Edison’s consolidated balance sheet includes $58 million in net assets (as detailed in the table below) and the non-controlling interest of the third party of $9 million related to Texas Solar 4. Earnings for the year ended December 31, 2015 and 2014 were immaterial.



(Millions of Dollars)	2015	2014
Restricted cash	$9	$13
Receivable from parent company	32	—
Non-utility property, less accumulated depreciation of $5 and $1, respectively	107	108
Other assets	11	14
Total assets (a)	$159	$135
Long-term debt due within one year	$2	$66
Other liabilities	37	11
Long-term debt	62	—
Total liabilities (b)	$101	$77


(a)	The assets of Texas Solar 4 represent assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE.


(b)	The liabilities of Texas Solar 4 represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

The following table summarizes the VIEs in which Con Edison Development has entered into as of December 31, 2015:



Project Name (a)	Generating Capacity (b) (MW AC)	Power Purchase Agreement Term in Years	Year of Initial Investment	Location	Maximum Exposure to Loss (Millions of Dollars) (c)
Copper Mountain Solar 3	128	20	2014	Nevada	$189
Panoche Valley	124	20	2015	California	114
Mesquite Solar 1	83	20	2013	Arizona	110
Copper Mountain Solar 2	75	25	2013	Nevada	85
California Solar	55	25	2012	California	75
Broken Bow II	38	25	2014	Nebraska	55
Pilesgrove	9	n/a (d)	2010	New Jersey	26
Texas Solar 4	32	25	2014	Texas	17


(a)	With the exception of Texas Solar 4, Con Edison’s ownership interest is 50 percent and these projects are accounted for using the equity method of accounting. Con Edison is not the primary beneficiary since the power to direct the activities that most significantly impact the economics of the entities are shared equally between Con Edison Development and third parties.


(b)	Represents Con Edison Development’s ownership interest in the project.

(c)

For investments accounted for under the equity method, maximum exposure is equal to the carrying value of the investment on the consolidated balance sheet and any related receivables due from the project. For consolidated investments, maximum exposure is equal to the net assets of the investment on the consolidated balance sheet less any applicable noncontrolling interest and receivables from the parent company. Con Edison did not provide any financial or other support during the year that was not previously contractually required.


(d)	Pilesgrove has 3-5 year Solar Renewable Energy Credit hedges in place.

CECONY

Variable Interest Entities

CECONY

Con Edison Development



(Millions of Dollars)
Proceeds from sale, net of transaction costs of $1	$108
Non-utility property, less accumulated depreciation	(341)
Other assets, including working capital	(31)
Long-term debt, including current portion	217
Other liabilities	9
Gain on sale of solar electric production projects	(45)
Equity method investment upon deconsolidation	$(83)



(Millions of Dollars)	2015	2014
Restricted cash	$9	$13
Receivable from parent company	32	—
Non-utility property, less accumulated depreciation of $5 and $1, respectively	107	108
Other assets	11	14
Total assets (a)	$159	$135
Long-term debt due within one year	$2	$66
Other liabilities	37	11
Long-term debt	62	—
Total liabilities (b)	$101	$77


(a)	The assets of Texas Solar 4 represent assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE.


(b)	The liabilities of Texas Solar 4 represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

The following table summarizes the VIEs in which Con Edison Development has entered into as of December 31, 2015:



Project Name (a)	Generating Capacity (b) (MW AC)	Power Purchase Agreement Term in Years	Year of Initial Investment	Location	Maximum Exposure to Loss (Millions of Dollars) (c)
Copper Mountain Solar 3	128	20	2014	Nevada	$189
Panoche Valley	124	20	2015	California	114
Mesquite Solar 1	83	20	2013	Arizona	110
Copper Mountain Solar 2	75	25	2013	Nevada	85
California Solar	55	25	2012	California	75
Broken Bow II	38	25	2014	Nebraska	55
Pilesgrove	9	n/a (d)	2010	New Jersey	26
Texas Solar 4	32	25	2014	Texas	17


(a)	With the exception of Texas Solar 4, Con Edison’s ownership interest is 50 percent and these projects are accounted for using the equity method of accounting. Con Edison is not the primary beneficiary since the power to direct the activities that most significantly impact the economics of the entities are shared equally between Con Edison Development and third parties.


(b)	Represents Con Edison Development’s ownership interest in the project.

(c)


(d)	Pilesgrove has 3-5 year Solar Renewable Energy Credit hedges in place.

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Asset Retirement Obligations	Asset Retirement Obligations The Companies recognize a liability at fair value for legal obligations associated with the retirement of long-lived assets in the period in which they are incurred, or when sufficient information becomes available to reasonably estimate the fair value of such legal obligations. When the liability is initially recorded, asset retirement costs are capitalized by increasing the carrying amount of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The fair value of the asset retirement obligation liability is measured using expected future cash flows discounted at credit-adjusted risk-free rates, historical information, and where available, quoted prices from outside contractors. The Companies evaluate these assumptions underlying the asset retirement obligation liability on an annual basis or as frequently as needed. The Companies recorded asset retirement obligations associated with the removal of asbestos and asbestos-containing material in their buildings (other than the structures enclosing generating stations and substations), electric equipment and steam and gas distribution systems. The Companies also recorded asset retirement obligations relating to gas and oil pipelines abandoned in place. The Companies did not record an asset retirement obligation for the removal of asbestos associated with the structures enclosing generating stations and substations. For these building structures, the Companies were unable to reasonably estimate their asset retirement obligations because the Companies were unable to estimate the undiscounted retirement costs or the retirement dates and settlement dates. The amount of the undiscounted retirement costs could vary considerably depending on the disposition method for the building structures, and the method has not been determined. The Companies anticipate continuing to use these building structures in their businesses for an indefinite period, and so the retirement dates and settlement dates are not determinable. Con Edison recorded asset retirement obligations for the removal of its competitive energy businesses’ solar and wind equipment related to projects located on property that is not owned by them and the term of the arrangement is finite including any renewal options. Con Edison did not record asset retirement obligations for its competitive energy businesses’ projects that are located on property that is owned by them because they expect that the equipment will continue to generate electricity at these facilities long past the manufacturer’s warranty at minimal operating expense. Therefore, Con Edison was unable to reasonably estimate the retirement date of this equipment. The Utilities include in depreciation rates the estimated removal costs, less salvage, for utility plant assets. The amounts related to removal costs that are associated with asset retirement obligations are classified as an asset retirement liability. Pursuant to accounting rules for regulated operations, future removal costs that do not represent legal asset retirement obligations are recorded as regulatory liabilities. Accretion and depreciation expenses related to removal costs that represent legal asset retirement obligations are applied against the Companies’ regulatory liabilities. Asset retirement costs that are recoverable from customers are recorded as regulatory liabilities to reflect the timing difference between costs recovered through the rate-making process and recognition of costs. At December 31, 2015, the liabilities for asset retirement obligations of Con Edison and CECONY were $242 million and $234 million, respectively. At December 31, 2014, the liabilities for asset retirement obligations of Con Edison and CECONY were $188 million and $185 million, respectively. The increase in liabilities at December 31, 2015 was due to changes in estimated cash flows of $82 million and $77 million for Con Edison and CECONY, respectively, and accretion expense of $8 million for both Con Edison and CECONY. The increases were offset in part by liabilities settled of $36 million for both Con Edison and CECONY. Con Edison and CECONY also recorded reductions of $23 million and $16 million during the years ended December 31, 2015 and 2014, respectively, to the regulatory liability associated with cost of removal to reflect depreciation and interest expense.
CECONY
Regulatory Liabilities [Line Items]
Asset Retirement Obligations	Asset Retirement Obligations The Companies recognize a liability at fair value for legal obligations associated with the retirement of long-lived assets in the period in which they are incurred, or when sufficient information becomes available to reasonably estimate the fair value of such legal obligations. When the liability is initially recorded, asset retirement costs are capitalized by increasing the carrying amount of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The fair value of the asset retirement obligation liability is measured using expected future cash flows discounted at credit-adjusted risk-free rates, historical information, and where available, quoted prices from outside contractors. The Companies evaluate these assumptions underlying the asset retirement obligation liability on an annual basis or as frequently as needed. The Companies recorded asset retirement obligations associated with the removal of asbestos and asbestos-containing material in their buildings (other than the structures enclosing generating stations and substations), electric equipment and steam and gas distribution systems. The Companies also recorded asset retirement obligations relating to gas and oil pipelines abandoned in place. The Companies did not record an asset retirement obligation for the removal of asbestos associated with the structures enclosing generating stations and substations. For these building structures, the Companies were unable to reasonably estimate their asset retirement obligations because the Companies were unable to estimate the undiscounted retirement costs or the retirement dates and settlement dates. The amount of the undiscounted retirement costs could vary considerably depending on the disposition method for the building structures, and the method has not been determined. The Companies anticipate continuing to use these building structures in their businesses for an indefinite period, and so the retirement dates and settlement dates are not determinable. Con Edison recorded asset retirement obligations for the removal of its competitive energy businesses’ solar and wind equipment related to projects located on property that is not owned by them and the term of the arrangement is finite including any renewal options. Con Edison did not record asset retirement obligations for its competitive energy businesses’ projects that are located on property that is owned by them because they expect that the equipment will continue to generate electricity at these facilities long past the manufacturer’s warranty at minimal operating expense. Therefore, Con Edison was unable to reasonably estimate the retirement date of this equipment. The Utilities include in depreciation rates the estimated removal costs, less salvage, for utility plant assets. The amounts related to removal costs that are associated with asset retirement obligations are classified as an asset retirement liability. Pursuant to accounting rules for regulated operations, future removal costs that do not represent legal asset retirement obligations are recorded as regulatory liabilities. Accretion and depreciation expenses related to removal costs that represent legal asset retirement obligations are applied against the Companies’ regulatory liabilities. Asset retirement costs that are recoverable from customers are recorded as regulatory liabilities to reflect the timing difference between costs recovered through the rate-making process and recognition of costs. At December 31, 2015, the liabilities for asset retirement obligations of Con Edison and CECONY were $242 million and $234 million, respectively. At December 31, 2014, the liabilities for asset retirement obligations of Con Edison and CECONY were $188 million and $185 million, respectively. The increase in liabilities at December 31, 2015 was due to changes in estimated cash flows of $82 million and $77 million for Con Edison and CECONY, respectively, and accretion expense of $8 million for both Con Edison and CECONY. The increases were offset in part by liabilities settled of $36 million for both Con Edison and CECONY. Con Edison and CECONY also recorded reductions of $23 million and $16 million during the years ended December 31, 2015 and 2014, respectively, to the regulatory liability associated with cost of removal to reflect depreciation and interest expense.

Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions

The Utilities and Con Edison’s competitive businesses provide administrative and other services to each other pursuant to cost allocation procedures approved by the NYSPSC. The costs of administrative and other services provided by CECONY to, and received by it from, Con Edison and its other subsidiaries for the years ended December 31, 2015, 2014 and 2013 were as follows:



	CECONY
(Millions of Dollars)	2015	2014	2013
Cost of services provided	$99	$90	$84
Cost of services received	60	57	52

In addition, CECONY and O&R have joint gas supply arrangements, in connection with which CECONY sold to O&R $54 million, $80 million and $72 million of natural gas for the years ended December 31, 2015, 2014 and 2013, respectively. These amounts are net of the effect of related hedging transactions.

FERC has authorized CECONY through 2017 to lend funds to O&R from time to time, for periods of not more than 12 months, in amounts not to exceed $250 million outstanding at any time, at prevailing market rates. There were no outstanding loans to O&R at December 31, 2015 and 2014.

In January 2016, CECONY entered into an agreement to sell certain electric transmission projects to NY Transco, a company in which CET Electric has a 45.7 percent ownership interest. Also, CECONY, O&R and NY Transco submitted a request to the NYSPSC for authorization in connection with the sale of the projects and the transfer of a substation from CECONY to O&R.

CECONY

Related Party Transactions



	CECONY
(Millions of Dollars)	2015	2014	2013
Cost of services provided	$99	$90	$84
Cost of services received	60	57	52

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

New Financial Accounting Standards	12 Months Ended
New Financial Accounting Standards	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Financial Accounting Standards	New Financial Accounting Standards In May 2014, the FASB and the International Accounting Standards Board (IASB) jointly issued a revenue recognition standard that will supersede the revenue recognition requirements within Accounting Standards Codification Topic 605, “Revenue Recognition,” and most industry-specific guidance under the Codification through ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The purpose of the new guidance is to create a consistent framework for revenue recognition. The guidance clarifies how to measure and recognize revenue arising from customer contracts to depict the transfer of goods or services in an amount that reflects the consideration the entity expects to receive. In August 2015, the FASB issued amendments to defer the effective date of ASU No. 2014-09 to reporting periods beginning after December 15, 2017 through ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date”. Early adoption is permitted for reporting periods beginning after December 15, 2016. The Companies are in the process of evaluating the application and impact of the new guidance on the Companies’ financial position, results of operations and liquidity. In January 2015, the FASB issued amendments on income statement guidance through ASU No. 2015-01, “Income Statement—Extraordinary and Unusual Items (Subtopic 225-20).” The amendments eliminate from GAAP the concept of extraordinary items. The amendments are effective for reporting periods beginning after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In February 2015, the FASB issued amendments on consolidation guidance through ASU No. 2015-02, “Consolidation (Topic 810).” The amendments provide additional guidance for VIE accounting of limited partnerships and similar legal entities, fees paid to decision makers of a VIE, the effect of fee arrangements on primary beneficiary determination, and the effect of related parties on primary beneficiary determination. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In April 2015, the FASB issued amendments on internal-use software guidance through ASU No. 2015-05, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The amendments provide guidance to customers about whether a cloud computing arrangement should be accounted for as a license of internal use software or as a service contract. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In May 2015, the FASB issued amendments on disclosure guidance for investments using Net Asset Value per Share through ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).” The amendments remove the requirement to categorize investments in the fair value hierarchy if Net Asset Value per Share is used as a practical expedient to determine the fair value of the investment. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In July 2015, the FASB issued amendments on the measurement of first-in, first-out and average cost inventory through ASU No.2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” The amendments require that inventory within the scope of the guidance be measured at the lower of cost and net realizable value rather than cost and market value. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2016. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In September 2015, the FASB issued an amendment to guidance for business combinations through ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments.” The amendment requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined as opposed to recognizing retrospectively. The amendment also requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. For public entities, the amendment is effective prospectively for reporting periods beginning after December 15, 2015. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In January 2016, the FASB issued amendments on certain aspects of recognition, measurement, presentation, and disclosure of financial instruments through ASU No. 2016-01, “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The amendments require changes to the accounting for equity investments, the presentation and disclosure requirements for financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, clarification was provided related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. For public entities, the amendments are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The Companies are in the process of evaluating the potential impact of the new guidance on the Companies’ financial position, results of operations and liquidity.
CECONY
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Financial Accounting Standards	New Financial Accounting Standards In May 2014, the FASB and the International Accounting Standards Board (IASB) jointly issued a revenue recognition standard that will supersede the revenue recognition requirements within Accounting Standards Codification Topic 605, “Revenue Recognition,” and most industry-specific guidance under the Codification through ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The purpose of the new guidance is to create a consistent framework for revenue recognition. The guidance clarifies how to measure and recognize revenue arising from customer contracts to depict the transfer of goods or services in an amount that reflects the consideration the entity expects to receive. In August 2015, the FASB issued amendments to defer the effective date of ASU No. 2014-09 to reporting periods beginning after December 15, 2017 through ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date”. Early adoption is permitted for reporting periods beginning after December 15, 2016. The Companies are in the process of evaluating the application and impact of the new guidance on the Companies’ financial position, results of operations and liquidity. In January 2015, the FASB issued amendments on income statement guidance through ASU No. 2015-01, “Income Statement—Extraordinary and Unusual Items (Subtopic 225-20).” The amendments eliminate from GAAP the concept of extraordinary items. The amendments are effective for reporting periods beginning after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In February 2015, the FASB issued amendments on consolidation guidance through ASU No. 2015-02, “Consolidation (Topic 810).” The amendments provide additional guidance for VIE accounting of limited partnerships and similar legal entities, fees paid to decision makers of a VIE, the effect of fee arrangements on primary beneficiary determination, and the effect of related parties on primary beneficiary determination. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In April 2015, the FASB issued amendments on internal-use software guidance through ASU No. 2015-05, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The amendments provide guidance to customers about whether a cloud computing arrangement should be accounted for as a license of internal use software or as a service contract. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In May 2015, the FASB issued amendments on disclosure guidance for investments using Net Asset Value per Share through ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).” The amendments remove the requirement to categorize investments in the fair value hierarchy if Net Asset Value per Share is used as a practical expedient to determine the fair value of the investment. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In July 2015, the FASB issued amendments on the measurement of first-in, first-out and average cost inventory through ASU No.2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” The amendments require that inventory within the scope of the guidance be measured at the lower of cost and net realizable value rather than cost and market value. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2016. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In September 2015, the FASB issued an amendment to guidance for business combinations through ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments.” The amendment requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined as opposed to recognizing retrospectively. The amendment also requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. For public entities, the amendment is effective prospectively for reporting periods beginning after December 15, 2015. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In January 2016, the FASB issued amendments on certain aspects of recognition, measurement, presentation, and disclosure of financial instruments through ASU No. 2016-01, “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The amendments require changes to the accounting for equity investments, the presentation and disclosure requirements for financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, clarification was provided related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. For public entities, the amendments are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The Companies are in the process of evaluating the potential impact of the new guidance on the Companies’ financial position, results of operations and liquidity.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6515603

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-Publisher FASB
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6503790

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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

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-Name Accounting Standards Codification
-Topic 270
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+ Details

Assets Held for Sale

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Assets Held for Sale

In June 2015, upon evaluating strategic alternatives, Con Edison initiated a plan to sell the retail electric supply business of its competitive energy businesses. The company expects the sale to close within the next twelve months. The company classified as held for sale the related assets and liabilities and ceased recording depreciation expense on these assets. There was no impairment of the assets held for sale, as the estimated fair value less costs to sell exceeded the carrying amount.

In October 2015, upon evaluating strategic alternatives, O&R entered into an agreement to sell Pike to Corning Natural Gas Holding Corporation for $16 million, including estimated working capital adjustments. The closing of the sale, which the company expects to occur within the next twelve months, is subject to certain regulatory approvals by the FERC and Pennsylvania Public Utility Commission. At December 31, 2015, the company classified the related electric and gas assets and liabilities as held for sale and ceased recording depreciation expense on these assets. O&R recorded an impairment charge of $5 million ($3 million net of taxes), representing the difference between the carrying amount of Pike’s assets and the estimated sales proceeds. The impairment is reported in other deductions on Con Edison's consolidated income statement for the year ended December 31, 2015 and reflected in the amount included in assets held for sale on the company's consolidated balance sheet at December 31, 2015.

At December 31, 2015, the carrying amounts of the assets and liabilities designated as held for sale were as follows:



(Millions of Dollars)	Retail Electric Supply Business		Pike		Total
Cash and temporary cash investments		$—	$4		$4
Accounts receivable, less allowance for uncollectible accounts of $8	64		—		64
Accrued unbilled revenue	64		1		65
Other assets	2		1		3
Total current assets	130		6		136
Utility plant, less accumulated depreciation of $6	—		14		14
Non-utility property, less accumulated depreciation of $13	4		—		4
Regulatory assets	—		3		3
Total assets held for sale	$134		$23		$157

Fair value of derivative liabilities	$65			$—	$65
Accounts payable	5		—		5
Other	1		2		3
Total current liabilities	71		2		73
Fair value of derivative liabilities	13		—		13
Long-term debt	—		3		3
Total liabilities held for sale	$84		$5		$89

- Definition

The entire disclosure related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=51716988&loc=SL51721533-107759

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-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4B
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+ Details

Schedule I - Condensed Financial Information

12 Months Ended

Dec. 31, 2015

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I - Condensed Financial Information

Schedule I

Condensed Financial Information of Consolidated Edison, Inc. (a)

Condensed Statement of Income and Comprehensive Income

(Parent Company Only)



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts)	2015	2014	2013
Equity in earnings of subsidiaries	$1,195	$1,101	$1,062
Other income (deductions), net of taxes	27	19	29
Interest expense	(29)	(28)	(29)
Net Income	$1,193	$1,092	$1,062
Comprehensive Income	$1,204	$1,072	$1,090
Net Income Per Share – Basic	$4.07	$3.73	$3.62
Net Income Per Share – Diluted	$4.05	$3.71	$3.61
Dividends Declared Per Share	$2.60	$2.52	$2.46
Average Number Of Shares Outstanding—Basic (In Millions)	293.0	292.9	292.9
Average Number Of Shares Outstanding—Diluted (In Millions)	294.4	294.0	294.4


(a)	These financial statements, in which Con Edison’s subsidiaries have been included using the equity method, should be read together with its consolidated financial statements and the notes thereto appearing above.

Condensed Financial Information of Consolidated Edison, Inc. (a)

Condensed Statement of Cash Flows

(Parent Company Only)



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Net Income	$1,193	$1,092	$1,062
Equity in earnings of subsidiaries	(1,195)	(1,101)	(1,062)
Dividends received from:
CECONY	872	712	728
O&R	81	40	38
Competitive energy businesses	8	8	12
Change in Assets:
Special deposits	—	314	(264)
Income taxes receivable	58	(224)	—
Other – net	(382)	(199)	166
Net Cash Flows from Operating Activities	635	642	680
Investing Activities
Contributions to subsidiaries	(15)	(1)	—
Net Cash Flows Used in Investing Activities	(15)	(1)	—
Financing Activities
Net proceeds of short-term debt	162	101	58
Retirement of long-term debt	(2)	(2)	(1)
Issuance of common shares for stock plans, net of repurchases	1	(10)	(8)
Common stock dividends	(733)	(739)	(721)
Net Cash Flows Used in Financing Activities	(572)	(650)	(672)
Net Change for the Period	48	(9)	8
Balance at Beginning of Period	3	12	4
Balance at End of Period	$51	$3	$12


(a)	These financial statements, in which Con Edison’s subsidiaries have been included using the equity method, should be read together with its consolidated financial statements and the notes thereto appearing above.

Condensed Financial Information of Consolidated Edison, Inc. (a)

Condensed Balance Sheet

(Parent Company Only)



	December 31,
(Millions of Dollars)	2015	2014
Assets
Current Assets
Cash and temporary cash investments	$51	$3
Special deposits	1	1
Accounts receivable – other	4	—
Income taxes receivable	166	224
Accounts receivable from affiliated companies	517	381
Prepayments	34	5
Other current assets	17	4
Total Current Assets	790	618
Investments in subsidiaries	12,737	12,277
Goodwill	406	406
Deferred income tax	11	18
Other noncurrent assets (b)	7	8
Total Assets	$13,951	$13,327
Liabilities and Shareholders’ Equity
Current Liabilities
Long-term debt due within one year	$2	$2
Notes payable	437	274
Accounts payable to affiliated companies	146	147
Accrued taxes	—	13
Other current liabilities	10	10
Total Current Liabilities	595	446
Total Liabilities	595	446
Long-term debt (b)	304	305
Shareholders’ Equity
Common stock, including additional paid-in capital	5,062	5,023
Retained earnings	7,990	7,553
Total Shareholders’ Equity	13,052	12,576
Total Liabilities and Shareholders’ Equity	$13,951	$13,327


(a)	These financial statements, in which Con Edison’s subsidiaries have been included using the equity method, should be read together with its consolidated financial statements and the notes thereto appearing above.


(b)	Reflects $3 million in 2014 related to the adoption of ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” See Note C.

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

Valuation and Qualifying Accounts Disclosure [Line Items]

Schedule II - Valuation and Qualifying Accounts

Schedule II

Valuation and Qualifying Accounts

For the Years Ended December 31, 2015, 2014 and 2013



				COLUMN C Additions
Company (Millions of Dollars)	COLUMN A Description		COLUMN B Balance at Beginning of Period	(1) Charged To Costs And Expenses	(2) Charged To Other Accounts		COLUMN D Deductions(b)	COLUMN E Balance At End of Period
Con Edison	Allowance for uncollectible accounts (a):
		2015	$106	$77		$—	$87	$96
		2014	$103	$98	—		$95	$106
		2013	$105	$86	—		$88	$103
CECONY	Allowance for uncollectible accounts (a):
		2015	$98	$69		$—	$76	$91
		2014	$95	$91	—		$88	$98
		2013	$96	$82	—		$83	$95


(a)	This is a valuation account deducted in the balance sheet from the assets (Accounts receivable - customers and Other receivables) to which they apply.


(b)	Accounts written off less cash collections, miscellaneous adjustments and amounts reinstated as receivables previously written off.

CECONY

Valuation and Qualifying Accounts Disclosure [Line Items]

Schedule II - Valuation and Qualifying Accounts

Schedule II

Valuation and Qualifying Accounts

For the Years Ended December 31, 2015, 2014 and 2013



				COLUMN C Additions
Company (Millions of Dollars)	COLUMN A Description		COLUMN B Balance at Beginning of Period	(1) Charged To Costs And Expenses	(2) Charged To Other Accounts		COLUMN D Deductions(b)	COLUMN E Balance At End of Period
Con Edison	Allowance for uncollectible accounts (a):
		2015	$106	$77		$—	$87	$96
		2014	$103	$98	—		$95	$106
		2013	$105	$86	—		$88	$103
CECONY	Allowance for uncollectible accounts (a):
		2015	$98	$69		$—	$76	$91
		2014	$95	$91	—		$88	$98
		2013	$96	$82	—		$83	$95


(a)	This is a valuation account deducted in the balance sheet from the assets (Accounts receivable - customers and Other receivables) to which they apply.


(b)	Accounts written off less cash collections, miscellaneous adjustments and amounts reinstated as receivables previously written off.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Companies’ consolidated financial statements include the accounts of their respective majority-owned subsidiaries, and variable interest entities (see Note Q), as required. All intercompany balances and transactions have been eliminated.
Accounting Policies	Accounting Policies The accounting policies of Con Edison and its subsidiaries conform to generally accepted accounting principles in the United States of America (GAAP). For the Utilities, these accounting principles include the accounting rules for regulated operations and the accounting requirements of the Federal Energy Regulatory Commission (FERC) and the state regulators having jurisdiction. The accounting rules for regulated operations specify the economic effects that result from the causal relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under the accounting rules for regulated operations. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under the accounting rules for regulated operations. The Utilities’ principal regulatory assets and liabilities are detailed in Note B. The Utilities are receiving or being credited with a return on all of their regulatory assets for which a cash outflow has been made, and are paying or being charged with a return on all of their regulatory liabilities for which a cash inflow has been received. The Utilities’ regulatory assets and liabilities will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable state regulators. Other significant accounting policies of the Companies are referenced below in this Note A and in the notes that follow.
Plant and Depreciation	Plant and Depreciation Utility Plant Utility plant is stated at original cost. The cost of repairs and maintenance is charged to expense and the cost of betterments is capitalized. The capitalized cost of additions to utility plant includes indirect costs such as engineering, supervision, payroll taxes, pensions, other benefits and an allowance for funds used during construction (AFUDC). The original cost of property is charged to expense over the estimated useful lives of the assets. Upon retirement, the original cost of property is charged to accumulated depreciation. See Note R. Rates used for AFUDC include the cost of borrowed funds and a reasonable rate of return on the Utilities’ own funds when so used, determined in accordance with regulations of the FERC or the state public utility regulatory authority having jurisdiction. The rate is compounded semiannually, and the amounts applicable to borrowed funds are treated as a reduction of interest charges, while the amounts applicable to the Utilities’ own funds are credited to other income (deductions). Non-Utility Plant Non-utility plant is stated at original cost. For Con Edison, non-utility plant consists primarily of the competitive energy businesses’ renewable electric production and gas storage. For the Utilities, non-utility plant consists of land and conduit for telecommunication use.
Goodwill	Goodwill Con Edison tests goodwill for impairment at least annually. There is an option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying a two-step, quantitative goodwill impairment test. However Con Edison has not elected to perform the qualitative assessment and exclusively applies the two-step quantitative approach. The first step of the goodwill impairment test compares the estimated fair value of a reporting unit with its carrying value, including goodwill. If the estimated fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is considered not impaired. If the carrying value exceeds the estimated fair value of the reporting unit, the second step is performed to measure the amount of impairment loss, if any. The second step requires a calculation of the implied fair value of goodwill. See Note K.
Impairments	Impairments Con Edison evaluates the impairment of long-lived assets, based on projections of undiscounted future cash flows, whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event an evaluation indicates that such cash flows cannot be expected to be sufficient to fully recover the assets, the assets are written down to their estimated fair value.
Revenues	Revenues The Utilities and Con Edison Solutions recognize revenues for energy service on a monthly billing cycle basis. The Utilities defer over a 12-month period net interruptible gas revenues, other than those authorized by the NYSPSC to be retained by the Utilities, for refund to firm gas sales and transportation customers. The Utilities and Con Edison Solutions accrue revenues at the end of each month for estimated energy service not yet billed to customers. CECONY’s electric and gas rate plans and O&R’s New York electric and gas rate plans each contain a revenue decoupling mechanism under which the company’s actual energy delivery revenues are compared with the authorized delivery revenues and the difference accrued, with interest, for refund to, or recovery from, customers, as applicable. See “Rate Plans” in Note B. The NYSPSC requires utilities to record gross receipts tax revenues and expenses on a gross income statement presentation basis (i.e., included in both revenue and expense). The recovery of these taxes is generally provided for in the revenue requirement within each of the respective NYSPSC approved rate plans.
Recoverable Energy Costs/New York Independent System Operator (NYISO)	Recoverable Energy Costs The Utilities generally recover all of their prudently incurred fuel, purchased power and gas costs, including hedging gains and losses, in accordance with rate provisions approved by the applicable state public utility regulators. If the actual energy supply costs for a given month are more or less than the amounts billed to customers for that month, the difference in most cases is recoverable from or refundable to customers. Differences between actual and billed electric and steam supply costs and costs of its electric demand management programs are generally deferred for charge or refund to customers during the next billing cycle (normally within one or two months). For the Utilities’ gas costs, differences between actual and billed gas costs during the 12-month period ending each August are charged or refunded to customers during a subsequent 12-month period. New York Independent System Operator (NYISO) The Utilities purchase electricity through the wholesale electricity market administered by the NYISO. The difference between purchased power and related costs initially billed to the Utilities by the NYISO and the actual cost of power subsequently calculated by the NYISO is refunded by the NYISO to the Utilities, or paid to the NYISO by the Utilities. The reconciliation payments or receipts are recoverable from or refundable to the Utilities’ customers. Certain other payments to or receipts from the NYISO are also subject to reconciliation, with shortfalls or amounts in excess of specified rate allowances recoverable from or refundable to customers. These include proceeds from the sale through the NYISO of transmission rights on CECONY’s transmission system (transmission congestion contracts or TCCs).
Temporary Cash Investments	Temporary Cash Investments Temporary cash investments are short-term, highly-liquid investments that generally have maturities of three months or less at the date of purchase. They are stated at cost, which approximates market. The Companies consider temporary cash investments to be cash equivalents.
Investments	Investments Investments consist primarily of the investments of Con Edison’s competitive energy businesses, which are accounted for under the equity method (depending on the subsidiaries’ percentage ownership). Utilities’ investments are recorded at fair value and include the investments of the deferred income plan and the supplemental retirement income plan in trust-owned life insurance assets.
Pension and Other Postretirement Benefits	Pension and Other Postretirement Benefits The accounting rules for retirement benefits require an employer to recognize an asset or liability for the overfunded or underfunded status of its pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. The accounting rules generally require employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in accumulated other comprehensive income (OCI), net of tax. Such amounts will be adjusted as they are subsequently recognized as components of total periodic benefit cost or income pursuant to the current recognition and amortization provisions. For the Utilities’ pension and other postretirement benefit plans, regulatory accounting treatment is generally applied in accordance with the accounting rules for regulated operations. Unrecognized prior service costs or credits and unrecognized actuarial gains and losses are recorded to regulatory assets or liabilities, rather than OCI. See Notes E and F. The total periodic benefit costs are recognized in accordance with the accounting rules for retirement benefits. Investment gains and losses are recognized in expense over a 15-year period and other actuarial gains and losses are recognized in expense over a 10-year period, subject to the deferral provisions in the rate plans. In accordance with the Statement of Policy issued by the NYSPSC and its current electric, gas and steam rate plans, CECONY defers for payment to or recovery from customers the difference between such expenses and the amounts for such expenses reflected in rates. Generally, O&R also defers such difference pursuant to its rate plans. See Note B. The Companies calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected rate of return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. The accounting rules allow the MRV of plan assets to be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. The Companies use a calculated value when determining the MRV of the plan assets that adjusts for 20 percent of the difference between fair value and expected MRV of plan assets. This calculated value has the effect of stabilizing variability in assets to which the Companies apply the expected return.
Federal Income Tax/State Income Tax	Federal Income Tax In accordance with the accounting rules for income taxes, the Companies have recorded an accumulated deferred federal income tax liability at current tax rates for temporary differences between the book and tax basis of assets and liabilities. In accordance with rate plans, the Utilities have recovered amounts from customers for a portion of the tax liability they will pay in the future as a result of the reversal or “turn-around” of these temporary differences. As to the remaining tax liability, in accordance with the accounting rules for regulated operations, the Utilities have established regulatory assets for the net revenue requirements to be recovered from customers for the related future tax expense. See Notes B and L. In 1993, the NYSPSC issued a Policy Statement approving accounting procedures consistent with the accounting rules for income taxes and providing assurances that these future increases in taxes will be recoverable in rates. See Note L. Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties and applied as a reduction to future federal income tax expense. Con Edison and its subsidiaries file a consolidated federal income tax return. The consolidated income tax liability is allocated to each member of the consolidated group using the separate return method. Each member pays or receives an amount based on its own taxable income or loss in accordance with tax sharing agreements among the members of the consolidated group. Tax loss carryforwards are allocated among members in accordance with consolidated tax return regulations. State Income Tax Con Edison and its subsidiaries file a combined New York State Corporation Business Franchise Tax Return. Similar to a federal consolidated income tax return, the income of all entities in the combined group is subject to New York State taxation, after adjustments for differences between federal and New York law and apportionment of income among the states in which the company does business. Each member’s share of the New York State tax is based on its own New York State taxable income or loss.
Research and Development Costs	Research and Development Costs Generally research and development costs are charged to operating expenses as incurred.
Reclassification	Reclassification Certain prior year amounts have been reclassified to conform with the current year presentation.
Earnings Per Common Share	Earnings Per Common Share Con Edison presents basic and diluted earnings per share on the face of its consolidated income statement. Basic earnings per share (EPS) are calculated by dividing earnings available to common shareholders (“Net income” on Con Edison’s consolidated income statement) by the weighted average number of Con Edison common shares outstanding during the period. In the calculation of diluted EPS, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for Con Edison consist of restricted stock units, deferred stock units and stock options for which the average market price of the common shares for the period was greater than the exercise price.
Estimates	Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
New Financial Accounting Standards	New Financial Accounting Standards In May 2014, the FASB and the International Accounting Standards Board (IASB) jointly issued a revenue recognition standard that will supersede the revenue recognition requirements within Accounting Standards Codification Topic 605, “Revenue Recognition,” and most industry-specific guidance under the Codification through ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The purpose of the new guidance is to create a consistent framework for revenue recognition. The guidance clarifies how to measure and recognize revenue arising from customer contracts to depict the transfer of goods or services in an amount that reflects the consideration the entity expects to receive. In August 2015, the FASB issued amendments to defer the effective date of ASU No. 2014-09 to reporting periods beginning after December 15, 2017 through ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date”. Early adoption is permitted for reporting periods beginning after December 15, 2016. The Companies are in the process of evaluating the application and impact of the new guidance on the Companies’ financial position, results of operations and liquidity. In January 2015, the FASB issued amendments on income statement guidance through ASU No. 2015-01, “Income Statement—Extraordinary and Unusual Items (Subtopic 225-20).” The amendments eliminate from GAAP the concept of extraordinary items. The amendments are effective for reporting periods beginning after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In February 2015, the FASB issued amendments on consolidation guidance through ASU No. 2015-02, “Consolidation (Topic 810).” The amendments provide additional guidance for VIE accounting of limited partnerships and similar legal entities, fees paid to decision makers of a VIE, the effect of fee arrangements on primary beneficiary determination, and the effect of related parties on primary beneficiary determination. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In April 2015, the FASB issued amendments on internal-use software guidance through ASU No. 2015-05, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The amendments provide guidance to customers about whether a cloud computing arrangement should be accounted for as a license of internal use software or as a service contract. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In May 2015, the FASB issued amendments on disclosure guidance for investments using Net Asset Value per Share through ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).” The amendments remove the requirement to categorize investments in the fair value hierarchy if Net Asset Value per Share is used as a practical expedient to determine the fair value of the investment. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2015. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In July 2015, the FASB issued amendments on the measurement of first-in, first-out and average cost inventory through ASU No.2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” The amendments require that inventory within the scope of the guidance be measured at the lower of cost and net realizable value rather than cost and market value. For public entities, the amendments are effective for reporting periods beginning on or after December 15, 2016. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In September 2015, the FASB issued an amendment to guidance for business combinations through ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments.” The amendment requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined as opposed to recognizing retrospectively. The amendment also requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. For public entities, the amendment is effective prospectively for reporting periods beginning after December 15, 2015. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In January 2016, the FASB issued amendments on certain aspects of recognition, measurement, presentation, and disclosure of financial instruments through ASU No. 2016-01, “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The amendments require changes to the accounting for equity investments, the presentation and disclosure requirements for financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, clarification was provided related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. For public entities, the amendments are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The Companies are in the process of evaluating the potential impact of the new guidance on the Companies’ financial position, results of operations and liquidity.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Capitalized Cost of Utility Plant

At December 31, 2015 and 2014, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Electric
Generation	$459	$451	$459	$451
Transmission	3,045	2,956	2,833	2,744
Distribution	17,244	16,361	16,394	15,531
Gas (a)	5,698	5,006	5,196	4,530
Steam	1,849	1,795	1,849	1,795
General	1,758	1,650	1,592	1,498
Held for future use	77	76	65	65
Construction work in progress	1,003	1,031	922	971
Net Utility Plant	$31,133	$29,326	$29,310	$27,585

(a) Primarily distribution.

Schedule of Total Excise Taxes Recorded in Operating Revenues

Total excise taxes (inclusive of gross receipts taxes) recorded in operating revenues were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$354	$365	$354
CECONY	331	343	329

Research and Development Costs

Research and development costs were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$23	$22	$18
CECONY	22	20	16

Earnings Per Common Share

Basic and diluted EPS for Con Edison are calculated as follows:



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts/Shares in Millions)	2015	2014	2013
Net income	$1,193	$1,092	$1,062
Weighted average common shares outstanding – basic	293.0	292.9	292.9
Add: Incremental shares attributable to effect of potentially dilutive securities	1.4	1.1	1.5
Adjusted weighted average common shares outstanding – diluted	294.4	294.0	294.4
Net Income per common share – basic	$4.07	$3.73	$3.62
Net Income per common share – diluted	$4.05	$3.71	$3.61

Changes in Accumulated Other Comprehensive Income by Component

Changes to accumulated other comprehensive income (OCI) for Con Edison and CECONY are as follows:



(Millions of Dollars)	Con Edison	CECONY
Accumulated OCI, net of taxes, at December 31, 2013	$(25)	$(6)
OCI before reclassifications, net of tax of $18 and $4 for Con Edison and CECONY, respectively	(26)	(6)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) for Con Edison and CECONY, respectively (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2014	(20)	(5)
Accumulated OCI, net of taxes, at December 31, 2014 (a)	$(45)	$(11)
OCI before reclassifications, net of tax of $(3) for Con Edison	5	1
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) for Con Edison and CECONY, respectively (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2015	11	2
Accumulated OCI, net of taxes, at December 31, 2015 (a)	$(34)	$(9)

(a) Tax reclassified from accumulated OCI is reported in the income tax expense line item of the income statement.

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2015

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2015 and 2014 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Regulatory assets
Unrecognized pension and other postretirement costs	$3,876	$4,846	$3,697	$4,609
Future income tax	2,350	2,259	2,232	2,142
Environmental remediation costs	904	925	800	820
Revenue taxes	253	219	240	208
Deferred storm costs	185	319	110	224
Unamortized loss on reacquired debt	50	57	48	55
Deferred derivative losses	50	25	46	23
O&R property tax reconciliation	46	36	—	—
Pension and other postretirement benefits deferrals	45	66	16	42
Surcharge for New York State assessment	44	99	40	92
Net electric deferrals	44	63	44	63
Preferred stock redemption	26	27	26	27
O&R transition bond charges	21	27	—	—
Recoverable energy costs	16	19	15	17
Workers’ compensation	11	8	11	8
Other	175	147	157	127
Regulatory assets – noncurrent	8,096	9,142	7,482	8,457
Deferred derivative losses	113	97	103	92
Recoverable energy costs	19	41	18	40
Regulatory assets – current	132	138	121	132
Total Regulatory Assets	$8,228	$9,280	$7,603	$8,589
Regulatory liabilities
Allowance for cost of removal less salvage	$676	$598	$570	$499
Property tax reconciliation	303	295	303	295
Base rate change deferrals	128	155	128	155
Net unbilled revenue deferrals	109	138	109	138
Prudence proceeding	99	105	99	105
Earnings sharing - electric and steam	80	19	80	18
Pension and other postretirement benefit deferrals	76	46	46	37
New York State income tax rate change	75	62	72	59
Variable-rate tax-exempt debt - cost rate reconciliation	70	78	60	78
Carrying charges on repair allowance and bonus depreciation	49	58	48	57
Property tax refunds	44	87	44	87
Net utility plant reconciliations	32	21	31	20
Unrecognized other postretirement costs	28	—	28	—
World Trade Center settlement proceeds	21	41	21	41
Other	187	290	150	248
Regulatory liabilities – noncurrent	1,977	1,993	1,789	1,837
Refundable energy costs	64	128	33	84
Revenue decoupling mechanism	45	30	45	30
Deferred derivative gains	6	5	6	4
Regulatory liabilities—current	115	163	84	118
Total Regulatory Liabilities	$2,092	$2,156	$1,873	$1,955

Rockland Electric Company (RECO)

Summary of Utilities Rate Plans



Rockland Electric Company (RECO)
Effective period	May 2010 – July 2014	August 2014 – July 2015 (a)
Base rate changes	Yr. 1 – $9.8 million	Yr. 1 – $13.0 million
Amortization to income of net regulatory (assets) and liabilities	$(3.9) million over four years and $(4.9) million of deferred storm costs over five years	$0.4 million over three years and $(25.6) million of deferred storm costs over four years
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$148.6 million	$172.2 million
Weighted average cost of capital (after-tax)	8.21 percent	7.83 percent
Authorized return on common equity	10.3 percent	9.75 percent
Cost of long-term debt	6.16 percent	5.89 percent
Common equity ratio	50 percent	50 percent


(a)	In January 2016, the NJBPU approved RECO’s plan for a 3-year, $15.7 million electric system storm hardening capital program, the costs of which RECO will, beginning in 2017, collect through a customer surcharge until a new rate plan is approved that reflects the costs.

Electric | CECONY

Summary of Utilities Rate Plans

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	April 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $420 million Yr. 2 – $420 million Yr. 3 – $287 million(b)	Yr. 1 – $(76.2) million (c) Yr. 2 – $124.0 million (c) Yr. 3 – None
Amortizations to income of net regulatory (assets) and liabilities	$(75.3) million over three years	Yr. 1 and 2 – $(37) million (d) Yr. 3 - $123 million (d)
Other revenue sources	Retention of $120 million of annual transmission congestion revenues from the sale of transmission rights ($90 million for the period April 1, 2013 to December 31, 2013).	Retention of $90 million of annual transmission congestion revenues.
Revenue decoupling mechanisms	In 2012 and 2013, the company deferred for customer benefit $59 million and $34 million of revenues, respectively.	In 2014 and 2015, the company deferred for customer benefit $146 million and $98 million of revenues, respectively.
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power and fuel costs (e).
Negative revenue adjustments	Potential penalties (up to $350 million annually) if certain performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (f)	In 2012 and 2013, the company deferred $146 million of net regulatory liabilities and $35 million of net regulatory assets, respectively.	In 2014 and 2015, the company deferred $57 million and $26 million of net regulatory liabilities, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $13,818 million Yr. 2 – $14,742 million Yr. 3 – $15,414 million Enterprise resource project: Yr. 2 – $25 million; Yr. 3 -$115 million; Other: Yr. 1 – $1,487 million; Yr. 2 – $1,565 million; Yr. 3 – $1,650 million The company deferred an immaterial amount and $7 million as a regulatory liability in 2012 and 2013, respectively.	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred an immaterial amount and $17 million as a regulatory liability in 2014 and 2015, respectively.
Average rate base	Yr. 1 – $14,887 million Yr. 2 – $15,987 million Yr. 3 – $16,826 million	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million
Weighted average cost of capital (after-tax)	7.76 percent	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent
Authorized return on common equity	10.15 percent assuming the company achieved austerity measures of $27 million, $20 million and $13 million for Yrs. 1, 2 and 3, respectively. Austerity measures were achieved.	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent
Earnings sharing	Actual earnings above an annual earnings threshold of 11.15 percent for Yr. 1 and 10.65 percent for Yrs. 2 and 3 were to be applied to reduce regulatory assets for pensions and other postretirement benefits and other costs. Actual earnings were $17.5 million above the threshold for the period ended 2013.	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $44.4 million above the threshold for 2015.
Cost of long-term debt	5.65 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent
Common equity ratio	48 percent	48 percent


(a)	$249 million of annual revenues collected from electric customers will continue to be subject to potential refund following NYSPSC staff review of certain costs. See "Other Regulatory Matters" below. Revenues for 2014 through 2016 will include $21 million as funding for major storm reserve.


(b)	Temporary portion of the increase ($134 million) that was scheduled to go into effect April 1, 2012 was eliminated by the application of available credits.


(c)	The impact of these base rate changes were deferred which resulted in a $30 million regulatory liability at December 31, 2015.

(d)

(e)

(f)

Electric | O&R

Summary of Utilities Rate Plans



O&R New York – Electric
Effective period	July 2012 – June 2015	November 2015 - October 2017
Base rate changes	Yr. 1 – $19.4 million Yr. 2 – $8.8 million Yr. 3 – $15.2 million	Yr. 1 – $9.3 million Yr. 2 – $8.8 million
Amortizations to income of net regulatory (assets) and liabilities	$(32.2) million over three years	Yr. 1 – $(8.5) million (a) Yr. 2 – $(9.4) million (a)
Revenue decoupling mechanisms	In 2012, 2013 and 2014, the company deferred for the customer’s benefit $2.6 million, $3.2 million and $(3.4) million.	In 2015, the company's deferral for the customer’s benefit was immaterial.
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power costs.
Negative revenue adjustments	Potential penalties (up to $3 million annually) if certain customer service and system reliability performance targets are not met. In 2012, 2013 and 2014, the company did not record any negative revenue adjustments.	Potential penalties (up to $4 million annually) if certain performance targets are not met. In 2015, the company recorded $1.25 million in negative revenue adjustments.
Cost reconciliations	In 2012, 2013 and 2014, the company deferred $7.8 million, $4.1 million and $(0.2) million as a net increase to regulatory assets, respectively.	In 2015, the company deferred $1.2 million as a net increase to regulatory assets.
Net utility plant reconciliations	Target levels reflected in rates were: Yr. 1 – $678 million; Yr. 2- $704 million; Yr. 3 – $753 million The company increased its regulatory liability by $4.2 million in 2012. The company reduced its regulatory liability by $1.1 million and $2.3 million in 2013 and 2014, respectively.	Target levels reflected in rates are: Yr. 1 – $928 million (b) Yr. 2 – $970 million (b) The company increased its regulatory asset by $2.2 million in 2015.
Average rate base	Yr. 1 – $671 million Yr. 2 – $708 million Yr. 3 – $759 million	Yr. 1 – $763 million Yr. 2 – $805 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.61 percent Yr. 2 – 7.65 percent Yr. 3 – 7.48 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent
Authorized return on common equity	Yr. 1 – 9.4 percent Yr. 2 – 9.5 percent Yr. 3 – 9.6 percent	9.0 percent
Earnings sharing	The company recorded a regulatory liability of $1 million for earnings above the sharing threshold under the rate plan as of December 31, 2014.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 6.07 percent Yr. 2 – 6.07 percent Yr. 3 – 5.64 percent	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent
Common equity ratio	48 percent	48 percent

(a)


(b)	Excludes electric advanced metering infrastructure as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.

Electric | Pike County Light & Power Company (Pike)

Summary of Utilities Rate Plans



Pike – Electric
Effective period	April 2009 – August 2014	September 2014 – August 2015
Base rate changes(a)	Yr. 1 – $0.9 million	Yr. 1 – $1.25 million
Amortization to income of net regulatory (assets) and liabilities	$0.1 million over five years	$(0.7) million of deferred storm costs over five years
Cost reconciliations	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as regulatory liabilities in 2012 and 2013.	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as a regulatory liability in 2014 and 2015.


(a)	Under the current plan, the earliest that the company can file for a new base rate change is September 1, 2016.

Gas | CECONY

Summary of Utilities Rate Plans



CECONY – Gas
Effective period	October 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $47 million Yr. 2 – $48 million Yr. 3 – $47 million	Yr. 1 – $(54.6) million (b) Yr. 2 – $38.6 million (b) Yr. 3 – $56.8 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$(53.1) million over three years	$4 million over three years
Other revenue sources	Retention of revenues from non-firm customers of up to $58 million and 25 percent of any such revenues above $58 million. The company retained $57 million and $64 million of such revenues in 2012 and 2013, respectively.	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million and $66 million of such revenues in 2014 and 2015, respectively.
Revenue decoupling mechanisms	In 2012 and 2013, the company deferred $22 million and $36 million of regulatory liabilities, respectively.	In 2014 and 2015, the company deferred $28 million and $54 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $12.6 million annually) if certain gas performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014 and 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (c)	In 2012 and 2013, the company deferred $9 million and $26 million of net regulatory assets, respectively.	In 2014 and 2015, the company deferred $38 million and $11 million of net regulatory liabilities, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $2,934 million; Yr. 2 – $3,148 million; Yr. 3 – $3,346 million For 2012 and 2013, $2.9 million and $9.5 million were deferred as a regulatory liability respectively.	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million There were no deferrals recorded in 2014. In 2015, $1 million was deferred as a regulatory liability.
Average rate base	Yr. 1 – $3,027 million Yr. 2 – $3,245 million Yr. 3 – $3,434 million	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million
Weighted average cost of capital (after-tax)	7.46 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity	9.6 percent assuming the company achieved unspecified austerity measures of $4 million and $2 million in 2012 and 2013. Austerity measures were achieved.	9.3 percent
Earnings sharing	Actual earnings did not exceed the thresholds of 10.35 percent in Yr. 1 and 10.15 percent in Yrs. 2 and 3.	Most earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014 and 2015, the company had no earnings above the threshold.
Cost of long-term debt	5.57 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio	48 percent	48 percent


(a)	$32 million of annual revenues collected from gas customers is subject to potential refund. See “Other Regulatory Matters” below.


(b)	The impact of these base rate changes is being deferred which will result in a $32 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.

Gas | O&R

Summary of Utilities Rate Plans



O&R New York – Gas
Effective period	November 2009 – December 2014	November 2015 – October 2018
Base rate changes	Yr. 1 – $9 million Yr. 2 – $9 million Yr. 3 – $4.6 million Yr. 3 – $4.3 million collected through a surcharge	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge
Amortization to income of net regulatory (assets) and liabilities	$(2) million over three years	Yr. 1 – $(1.7) million (a) Yr. 2 – $(2.1) million (a) Yr. 3 – $(2.5) million (a)
Revenue decoupling mechanisms	In 2012, 2013 and 2014, the company deferred $4.7 million, $0.7 million and $(0.1) million of regulatory liabilities, respectively.	In 2015, the company deferred $0.8 million of regulatory assets.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $1.4 million annually) if certain operations and customer service requirements are not met. In 2012, 2013 and 2014, the company did not record any negative revenue adjustments.	Potential penalties (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $5.8 million in Yr. 3) if certain performance targets are not met. In 2015, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2012, 2013 and 2014, the company deferred $0.7 million, $8.3 million and $8.3 million as net regulatory assets, respectively.	In 2015, the company deferred $2.5 million as net regulatory assets.
Net utility plant reconciliations	The company deferred $0.7 million in 2012 as a regulatory asset and no deferrals were recorded for 2013 or 2014.	Target levels reflected in rates are: Yr. 1 – $492 million (b) Yr. 2 – $518 million (b) Yr. 3 – $546 million (b) The company recorded no deferrals in 2015.
Average rate base	Yr. 1 – $280 million Yr. 2 – $296 million Yr. 3 – $309 million	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million
Weighted average cost of capital (after-tax)	8.49 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent
Authorized return on common equity	10.4 percent	9.0 percent
Earnings sharing	Earnings above an annual earnings threshold of 11.4 percent are to be applied to reduce regulatory assets. In 2012, 2013 and 2014, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold.
Cost of long-term debt	6.81 percent	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent
Common equity ratio	48 percent	48 percent


(a)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(b)	Excludes gas advanced metering infrastructure as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.

Gas | Pike County Light & Power Company (Pike)

Summary of Utilities Rate Plans



Pike – Gas
Effective period	April 2009 – August 2014	September 2014 – August 2015
Base Rate changes(a)	Yr. 1 – $0.3 million	Yr. 1 – $0.1 million
Amortization to income of net regulatory (assets) and liabilities	None	None
Cost reconciliations	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as regulatory liabilities in 2012 and 2013.	True-up of Other Postretirement Benefits costs. The company deferred an immaterial amount as a regulatory liability in 2014 and 2015.


(a)	Under the current plan, the earliest that the company can file for a new base rate change is September 1, 2016.

Steam | CECONY

Summary of Utilities Rate Plans



CECONY – Steam
Effective period	October 2010 – December 2013	January 2014 – December 2016
Base rate changes (a)	Yr. 1 – $49.5 million Yr. 2 – $49.5 million Yr. 3 – $17.8 million Yr. 3 – $31.7 million collected through a surcharge	Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$(20.1) million over three years	$37 million over three years
Recoverable energy costs	Current rate recovery of purchased power and fuel costs.	Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2012 and 2013, the company did not record any negative revenue adjustments.	Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014 and 2015, the company did not record any negative revenue adjustments.
Cost reconciliations (c)	In 2012 and 2013, the company deferred $12 million and $17 million of net regulatory liabilities, respectively.	In 2014 and 2015, the company deferred $42 million and $17 million of net regulatory liabilities and assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Production: Yr. 1 – $415 million; Yr. 2 – $426 million; Yr. 3 – $433 million Distribution: Yr. 1 – $521 million; Yr. 2 – $534 million; Yr. 3 – $543 million The company reduced its regulatory liability by $0.2 million in 2012 and made no deferral in 2013.	Target levels reflected in rates were: Production: Yr. 1 – $1,752 million; Yr. 2 – $1,732 million; Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million; Yr. 2 – $11 million; Yr. 3 – $25 million The company reduced its regulatory liability by $1.1 million and an immaterial amount in 2014 and 2015, respectively.
Average rate base	Yr. 1 – $1,589 million Yr. 2 – $1,603 million Yr. 3 – $1,613 million	Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)	7.46 percent	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity	9.6 percent (assuming company achieved unspecified austerity measures of $3 million and $2 million in 2012 and 2013). Austerity measures were achieved.	9.3 percent
Earnings sharing	Weather normalized earnings did not exceed the threshold of 10.35 percent in Yr. 1 and 10.15 percent in Yrs. 2 and 3. In 2013, actual earnings were $0.5 million above the earnings threshold of 10.15 percent.	Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $17.1 million above the threshold for 2015.
Cost of long-term debt	5.57 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio	48 percent	48 percent


(a)	$6 million of annual revenues collected from steam customers is subject to potential refund. See “Other Regulatory Matters” below.


(b)	The impact of these base rate changes is being deferred which will result in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent (80 percent prior to 2014) of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.

Capitalization (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Long-Term Debt Maturities

Long-term debt maturing in the period 2016-2020 is as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$739	$650
2017	16	—
2018	1,266	1,200
2019	552	475
2020	365	350

Carrying Amounts and Fair Values of Long-Term Debt

The carrying amounts and fair values of long-term debt at December 31, 2015 and 2014 are:



(Millions of Dollars)	2015		2014
Long-Term Debt (including current portion)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$12,745	$13,856	$12,106	$13,913
CECONY	$11,437	$12,427	$11,138	$12,770

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Pension Benefits (Tables) - Pension Benefits

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Total Periodic Benefit Costs

The components of the Companies’ total periodic benefit costs for 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Service cost – including administrative expenses	$297	$227	$267	$279	$211	$249
Interest cost on projected benefit obligation	575	572	537	538	536	503
Expected return on plan assets	(886)	(832)	(750)	(840)	(789)	(713)
Recognition of net actuarial loss	775	618	832	734	586	788
Recognition of prior service costs	4	4	5	2	2	4
NET PERIODIC BENEFIT COST	$765	$589	$891	$713	$546	$831
Amortization of regulatory asset (a)	1	2	2	1	2	2
TOTAL PERIODIC BENEFIT COST	$766	$591	$893	$714	$548	$833
Cost capitalized	(301)	(225)	(348)	(285)	(212)	(327)
Reconciliation to rate level	(74)	118	(84)	(74)	108	(87)
Cost charged to operating expenses	$391	$484	$461	$355	$444	$419

(a) Relates to an increase in CECONY’s pension obligation of $45 million from a 1999 special retirement program.

Schedule of Funded Status

The funded status at December 31, 2015, 2014 and 2013 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$15,081	$12,197	$13,406	$14,137	$11,429	$12,572
Service cost – excluding administrative expenses	293	221	259	274	206	241
Interest cost on projected benefit obligation	575	572	537	538	536	503
Net actuarial (gain)/loss	(996)	2,641	(1,469)	(931)	2,484	(1,388)
Plan amendments	—	6	—	—	—	—
Benefits paid	(576)	(556)	(536)	(536)	(518)	(499)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$14,377	$15,081	$12,197	$13,482	$14,137	$11,429
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$11,495	$10,755	$9,135	$10,897	$10,197	$8,668
Actual return on plan assets	126	752	1,310	118	715	1,241
Employer contributions	750	578	879	697	535	819
Benefits paid	(576)	(556)	(536)	(536)	(518)	(499)
Administrative expenses	(36)	(34)	(33)	(35)	(32)	(32)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$11,759	$11,495	$10,755	$11,141	$10,897	$10,197
FUNDED STATUS	$(2,618)	$(3,586)	$(1,442)	$(2,341)	$(3,240)	$(1,232)
Unrecognized net loss	$3,909	$4,888	$2,759	$3,704	$4,616	$2,617
Unrecognized prior service costs	16	20	17	3	4	6
Accumulated benefit obligation	12,909	13,454	11,004	12,055	12,553	10,268

Schedule of Assumptions

The actuarial assumptions were as follows:



	2015		2014		2013
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	4.25	%	3.90	%	4.80	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.35	%
O&R	4.00	%	4.00	%	4.25	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	3.90	%	4.80	%	4.10	%
Expected return on plan assets	7.80	%	8.00	%	8.00	%
Rate of compensation increase
CECONY	4.25	%	4.35	%	4.35	%
O&R	4.00	%	4.25	%	4.25	%

Schedule of Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years:



(Millions of Dollars)	2016	2017	2018	2019	2020	2021-2025
Con Edison	$614	$636	$658	$680	$701	$3,800
CECONY	572	593	614	635	655	3,548

Schedule of Plan Assets Allocations

The asset allocations for the pension plan at the end of 2015, 2014 and 2013, and the target allocation for 2016 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2016	2015		2014		2013
Equity Securities	55% - 65%	57	%	58	%	60	%
Debt Securities	27% - 33%	33	%	32	%	30	%
Real Estate	8% - 12%	10	%	10	%	10	%
Total	100%	100	%	100	%	100	%

Schedule of Fair Value of Plan Assets

The fair values of the pension plan assets at December 31, 2014 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Level 3		Total
U.S. Equity (a)	$3,168		$—		$—	$3,168
International Equity (b)	2,841	361		—		3,202
Private Equity (c)	—	—		114		114
U.S. Government Issued Debt (d)	—	2,113		—		2,113
Corporate Bonds Debt (e)	—	1,351		—		1,351
Structured Assets Debt (f)	—	4		—		4
Other Fixed Income Debt (g)	—	208		—		208
Real Estate (h)	—	—		1,137		1,137
Cash and Cash Equivalents (i)	188	477		—		665
Futures (j)	192	37		—		229
Hedge Funds (k)	—	—		224		224
Total investments	$6,389	$4,551		$1,475		$12,415
Funds for retiree health benefits (l)	(184)	(131)		(43)		(358)
Investments (excluding funds for retiree health benefits)	$6,205	$4,420		$1,432		$12,057
Pending activities (m)						(562)
Total fair value of plan net assets						$11,495


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	Private Equity consists of global equity funds that are not exchange-traded.


(d)	U.S. Government Issued Debt includes agency and treasury securities.


(e)	Corporate Bonds Debt consists of debt issued by various corporations.


(f)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(g)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(h)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(i)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(j)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.

The fair values of the pension plan assets at December 31, 2015 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Level 3		Total
U.S. Equity (a)	$3,106		$—		$—	$3,106
International Equity (b)	2,874	346		—		3,220
Private Equity (c)	—	—		170		170
U.S. Government Issued Debt (d)	—	2,222		—		2,222
Corporate Bonds Debt (e)	—	1,356		—		1,356
Structured Assets Debt (f)	—	1		—		1
Other Fixed Income Debt (g)	—	170		—		170
Real Estate (h)	—	—		1,248		1,248
Cash and Cash Equivalents (i)	115	414		—		529
Futures (j)	161	132		—		293
Hedge Funds (k)	—	—		233		233
Total investments	$6,256	$4,641		$1,651		$12,548
Funds for retiree health benefits (l)	(162)	(120)		(43)		(325)
Investments (excluding funds for retiree health benefits)	$6,094	$4,521		$1,608		$12,223
Pending activities (m)						(464)
Total fair value of plan net assets						$11,759


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	Private Equity consists of global equity funds that are not exchange-traded.


(d)	U.S. Government Issued Debt includes agency and treasury securities.


(e)	Corporate Bonds Debt consists of debt issued by various corporations.


(f)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(g)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(h)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(i)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(j)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.

Reconciliation of Fair Value Balances for Net Assets

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2014 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2014	Assets Still Held at Reporting Date – Unrealized Gains/(Losses)	Assets Sold During the Year – Realized Gains/(Losses)	Purchases Sales and Settlements	Transfer In/(Out) of Level 3		Ending Balance as of December 31, 2014
Real Estate	$1,062	$86	$20	$(31)		$—	$1,137
Private Equity	67	12	—	35	—		114
Hedge Funds	206	11	—	7	—		224
Total investments	$1,335	$109	$20	$11		$—	$1,475
Funds for retiree health benefits	(42)	(1)	—	—	—		(43)
Investments (excluding funds for retiree health benefits)	$1,293	$108	$20	$11		$—	$1,432

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2015 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2015	Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	Assets Sold During the Year – Realized Gains/(Losses)	Purchases Sales and Settlements	Transfer In/(Out) of Level 3		Ending Balance as of December 31, 2015
Real Estate	$1,137	$131	$12	$(32)		$—	$1,248
Private Equity	114	17	—	39	—		170
Hedge Funds	224	3	—	6	—		233
Total investments	$1,475	$151	$12	$13		$—	$1,651
Funds for retiree health benefits	(43)	—	—	—	—		(43)
Investments (excluding funds for retiree health benefits)	$1,432	$151	$12	$13		$—	$1,608

Schedule of Employer Contribution to Defined Savings Plan

The Companies also offer a defined contribution savings plan that covers substantially all employees and made contributions to the plan as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Con Edison	$34	$32	$30
CECONY	29	27	26

Other Postretirement Benefits (Tables) - Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Net Periodic Benefit Costs

The components of the Companies’ total periodic postretirement benefit costs for 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Service cost	$20	$19	$23	$15	$15	$18
Interest cost on accumulated other postretirement benefit obligation	51	60	54	43	52	46
Expected return on plan assets	(78)	(77)	(77)	(68)	(68)	(68)
Recognition of net actuarial loss	31	57	65	28	51	57
Recognition of prior service cost	(20)	(19)	(27)	(14)	(15)	(23)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST	$4	$40	$38	$4	$35	$30
Cost capitalized	(2)	(15)	(15)	(2)	(14)	(12)
Reconciliation to rate level	14	10	58	6	2	50
Cost charged to operating expenses	$16	$35	$81	$8	$23	$68

Schedule of Funded Status

The funded status of the programs at December 31, 2015, 2014 and 2013 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,411	$1,395	$1,454	$1,203	$1,198	$1,238
Service cost	20	19	23	15	15	18
Interest cost on accumulated postretirement benefit obligation	51	60	54	43	52	46
Amendments	—	(12)	—	—	—	—
Net actuarial loss/(gain)	(103)	47	(42)	(85)	28	(20)
Benefits paid and administrative expenses	(127)	(134)	(136)	(117)	(125)	(126)
Participant contributions	35	36	38	34	35	38
Medicare prescription subsidy	—	—	4	—	—	4
BENEFIT OBLIGATION AT END OF YEAR	$1,287	$1,411	$1,395	$1,093	$1,203	$1,198
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$1,084	$1,113	$1,047	$950	$977	$922
Actual return on plan assets	(6)	59	153	(4)	54	134
Employer contributions	6	7	9	6	7	9
EGWP payments	28	12	8	26	11	7
Participant contributions	35	36	38	34	35	38
Benefits paid	(153)	(143)	(142)	(142)	(134)	(133)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$994	$1,084	$1,113	$870	$950	$977
FUNDED STATUS	$(293)	$(327)	$(282)	$(223)	$(253)	$(221)
Unrecognized net loss	$28	$78	$70	$4	$45	$54
Unrecognized prior service costs	(51)	(71)	(78)	(32)	(46)	(61)

Schedule of Actuarial Assumptions

The actuarial assumptions were as follows:



	2015		2014		2013
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	4.05	%	3.75	%	4.50	%
O&R	4.20	%	3.85	%	4.75	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	3.75	%	4.50	%	3.75	%
O&R	3.85	%	4.75	%	4.05	%
Expected Return on Plan Assets	7.75	%	7.75	%	7.75	%

Schedule of Change of Assumed Health Care Cost Trend Rate

A one-percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2016:



	Con Edison		CECONY
	1-Percentage-Point
(Millions of Dollars)	Increase	Decrease	Increase	Decrease
Effect on accumulated other postretirement benefit obligation	$(18)	$41	$(37)	$56
Effect on service cost and interest cost components for 2015	(1)	1	(3)	2

Schedule of Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years, net of receipt of governmental subsidies:



(Millions of Dollars)	2016	2017	2018	2019	2020	2021-2025
Con Edison	$95	$93	$91	$88	$85	$403
CECONY	85	83	81	78	75	348

Schedule of Plan Assets Allocations

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2015, 2014 and 2013, and the target allocation for 2016 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2016	2015		2014		2013
Equity Securities	57% - 73%	59	%	59	%	61	%
Debt Securities	26% - 44%	41	%	41	%	39	%
Total	100%	100	%	100	%	100	%

Schedule of Fair Values of Plan Assets

The fair values of the plan assets at December 31, 2015 by asset category as defined by the accounting rules for fair value measurements (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Level 3		Total
Equity (a)		$—	$393		$—	$393
Other Fixed Income Debt (b)	—		260	—		260
Cash and Cash Equivalents (c)	—		7	—		7
Total investments		$—	$660		$—	$660
Funds for retiree health benefits (d)	162		120	43		325
Investments (including funds for retiree health benefits)	$162		$780	$43		$985
Pending activities (e)						9
Total fair value of plan net assets						$994


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Barclays Capital Aggregate Index.


(c)	Cash and Cash Equivalents include short term investments and money markets.

(d)


(e)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year end.

The fair values of the plan assets at December 31, 2014 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Level 3		Total
Equity (a)		$—	$428		$—	$428
Other Fixed Income Debt (b)	—		286	—		286
Cash and Cash Equivalents (c)	—		11	—		11
Total investments		$—	$725		$—	$725
Funds for retiree health benefits (d)	184		131	43		358
Investments (including funds for retiree health benefits)	$184		$856	$43		$1,083
Pending activities (e)						1
Total fair value of plan net assets						$1,084


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Barclays Capital Aggregate Index.


(c)	Cash and Cash Equivalents include short term investments and money markets.

(d)


(e)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year end.

Reconciliation of Fair Value Balances for Net Assets

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2014 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2014		Assets Still Held at Reporting Date – Unrealized Gains/(Losses)		Assets Sold During the Year – Realized Gains/(Losses)		Purchases Sales and Settlements		Transfers In/(Out) of Level 3		Ending Balance as of December 31, 2014
Total investments		$—		$—		$—		$—		$—		$—
Funds for retiree health benefits	42		1		—		—		—		43
Investments (including funds for retiree health benefits)	$42		$1			$—		$—		$—	$43

The table below provides a reconciliation of the beginning and ending net balances for assets at December 31, 2015 classified as Level 3 in the fair value hierarchy.



(Millions of Dollars)	Beginning Balance as of January 1, 2015		Assets Still Held at Reporting Date – Unrealized Gains/(Losses)		Assets Sold During the Year – Realized Gains/(Losses)		Purchases Sales and Settlements		Transfers In/(Out) of Level 3		Ending Balance as of December 31, 2015
Total investments		$—		$—		$—		$—		$—		$—
Funds for retiree health benefits	43		—		—		—		—		43
Investments (including funds for retiree health benefits)	$43			$—		$—		$—		$—	$43

Environmental Matters (Tables)

12 Months Ended

Dec. 31, 2015

Environmental Remediation Obligations [Abstract]

Accrued Liabilities and Regulatory Assets

The accrued liabilities and regulatory assets related to Superfund Sites at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Accrued Liabilities:
Manufactured gas plant sites	$679	$684	$579	$587
Other Superfund Sites	86	80	86	79
Total	$765	$764	$665	$666
Regulatory assets	$904	$925	$800	$820

Environmental Remediation Costs

Environmental remediation costs incurred and insurance recoveries received related to Superfund Sites at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Remediation costs incurred	$37	$29	$34	$20
Insurance recoveries received (a)	—	7	—	7

(a) Reduced amount deferred for recovery from customers

Accrued Liability for Asbestos Suits and Workers' Compensation Proceedings

The accrued liability for asbestos suits and workers’ compensation proceedings (including those related to asbestos exposure) and the amounts deferred as regulatory assets for the Companies at December 31, 2015 and 2014 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Accrued liability – asbestos suits	$8	$8	$7	$7
Regulatory assets – asbestos suits	$8	$8	$7	$7
Accrued liability – workers’ compensation	$86	$83	$81	$78
Regulatory assets – workers’ compensation	$11	$8	$11	$8

Other Material Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Total Guarantees

A summary, by type and term, of Con Edison’s total guarantees at December 31, 2015 is as follows:



Guarantee Type	0 – 3 years	4 – 10 years	> 10 years		Total
	(Millions of Dollars)
NY Transco	$791	$567		$—	$1,358
Energy transactions	792	35	97		924
Renewable electric production projects	471	1	27		499
Other	75	—	—		75
Total	$2,129	$603	$124		$2,856

Electricity Purchase Agreements (Tables)

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

Summary of Significant Terms of Electricity Purchase Agreements

At December 31, 2015, the significant terms of the electricity purchase agreements with non-utility generators were as follows:



Facility	Equity Owner	Plant Output (MW)	Contracted Output (MW)	Contract Start Date	Contract Term (Years)
Brooklyn Navy Yard	Brooklyn Navy Yard Cogeneration Partners, LP	322	299	November 1996	40
Linden Cogeneration	Cogen Technologies Linden Venture, LP	1,035	609	May 1992	25
Indian Point	Entergy Nuclear Power Marketing, LLC	2,311	500	August 2001	16
Astoria Energy	Astoria Energy, LLC	640	500	May 2006	10

Summary of Estimated Capacity and Other Fixed Payments

The future capacity and other fixed payments under the contracts are estimated to be as follows:



(Millions of Dollars)	2016	2017	2018	2019	2020	All Years Thereafter
Con Edison	$222	$207	$181	$98	$53	$762
CECONY	218	205	181	98	53	762

Summary of Capacity, Energy and Other Fixed Payments

The company’s payments under the agreements for capacity, energy and other fixed payments in 2015, 2014 and 2013 were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2015	2014	2013
Linden Cogeneration	$323	$381	$346
Indian Point	226	247	220
Astoria Energy	178	230	183
Brooklyn Navy Yard	113	133	118
Indeck Corinth (a)	25	80	79
Selkirk (b)	—	144	215
Independence (b)	—	97	121
Total	$865	$1,312	$1,282

(a) Contract term ended in 2015.

(b) Contract term ended in 2014.

Leases (Tables)

12 Months Ended

Dec. 31, 2015

Leases [Abstract]

Schedule of Capital Leases

The following assets under capital leases are included in the Companies’ consolidated balance sheets at December 31, 2015 and 2014:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
UTILITY PLANT
Common	$3	$3	$2	$1

Future Minimum Lease Commitments

The future minimum lease commitments for the above assets are as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$1	$1
2017	1	1
2018	1	1
2019	—	—
2020	—	—
All years thereafter	—	—
Total	3	3
Less: amount representing interest	1	1
Present value of net minimum lease payment	$2	$2

Future Minimum Rental Payments for Operating Leases

Operating leases: The future minimum lease commitments under the Companies’ non-cancelable operating lease agreements are as follows:



(Millions of Dollars)	Con Edison	CECONY
2016	$18	$12
2017	18	12
2018	18	12
2019	16	10
2020	15	9
All years thereafter	123	42
Total	$208	$97

Schedule of Leveraged Lease Transactions Effect on Consolidated Income Statement

The effect on Con Edison’s consolidated income statement for the twelve months ended as of December 31, 2014 and 2013 was as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2014		2013
Increase/(decrease) to non-utility operating revenues		$—	$(27)
(Increase)/decrease to other interest expense	13		(131)
Income tax benefit/(expense)	(14)		63
Total increase/(decrease) in net income	$(1)		$(95)

Income Tax (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
State
Current	$38	$59	$151	$48	$66	$111
Deferred	93	61	(70)	82	65	(14)
Federal
Current	(86)	(9)	285	77	158	187
Deferred	569	463	115	372	271	241
Amortization of investment tax credits	(9)	(6)	(5)	(5)	(5)	(5)
Total income tax expense	$605	$568	$476	$574	$555	$520

Schedule of Differences on Deferred Tax Assets and Liabilities

The tax effects of temporary differences, which gave rise to deferred tax assets and liabilities, are as follows:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Deferred tax liabilities:
Property basis differences	$8,614	$7,510	$7,922	$6,938
Regulatory assets:
Unrecognized pension and other postretirement costs	1,562	1,968	1,490	1,872
Future income tax	947	910	899	863
Environmental remediation costs	365	376	322	333
Deferred storm costs	75	129	45	91
Other regulatory assets	367	347	308	300
Equity investments	295	168	—	—
Total deferred tax liabilities	$12,225	$11,408	$10,986	$10,397
Deferred tax assets:
Accrued pension and other postretirement costs	$982	$1,306	$857	$1,155
Regulatory liabilities	836	615	752	574
Superfund and other environmental costs	308	306	268	264
Asset retirement obligations	97	77	94	75
Loss carryforwards	29	21	—	—
Tax credits carryforward	258	—	1	—
Valuation allowance	(15)	(11)	—	—
Other	362	272	292	203
Total deferred tax assets	2,857	2,586	2,264	2,271
Net deferred tax liabilities	$9,368	$8,822	$8,722	$8,126
Unamortized investment tax credits	169	126	33	37
Net deferred tax liabilities and unamortized investment tax credits	$9,537	$8,948	$8,755	$8,163

Schedule of Income Tax Reconciliation

Reconciliation of the difference between income tax expense and the amount computed by applying the prevailing statutory income tax rate to income before income taxes is as follows:



	Con Edison						CECONY
(% of Pre-tax income)	2015		2014		2013		2015		2014		2013
STATUTORY TAX RATE
Federal	35	%	35	%	35	%	35	%	35	%	35	%
Changes in computed taxes resulting from:
State income tax	5		5		4		5		5		5
Cost of removal	(5	)	(5	)	(5	)	(5	)	(5	)	(5	)
Manufacturing deduction	—		—		(1	)	—		—		—
Other	(1	)	(1	)	(2	)	—		(1	)	(1	)
Effective tax rate	34	%	34	%	31	%	35	%	34	%	34	%

Summary of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amounts of unrecognized tax benefits for Con Edison and CECONY follows:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014		2013
Balance at January 1,	$34	$9	$86	$2		$—	$74
Additions based on tax positions related to the current year	—	—	5	—	—		—
Additions based on tax positions of prior years	1	27	253	—	2		—
Reductions for tax positions of prior years	—	(2)	(86)	—	—		(74)
Reductions from expiration of statute of limitations	(1)	—	—	—	—		—
Settlements	—	—	(249)	—	—		—
Balance at December 31,	$34	$34	$9	$2	$2			$—

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Stock-Based Compensation Expense

The following table summarizes stock-based compensation expense recognized by the Companies in the years ended December 31, 2015, 2014 and 2013:



	Con Edison			CECONY
(Millions of Dollars)	2015	2014	2013	2015	2014	2013
Performance-based restricted stock	$27	$22	$20	$23	$19	$18
Time-based restricted stock	1	2	2	1	2	2
Non-employee director deferred stock compensation	2	2	2	2	2	2
Stock purchase plan	4	3	3	3	3	3
Total	$34	$29	$27	$29	$26	$25
Income tax benefit	$14	$12	$11	$12	$10	$10

Summary of Status of Stock Options

A summary of changes in the status of stock options as of December 31, 2015 is as follows:



	Con Edison		CECONY
	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price
Outstanding at December 31, 2014	229,850	$42.99	191,350	$43.00
Exercised	150,225	42.71	125,575	42.74
Forfeited	500	43.50	—	—
Outstanding at December 31, 2015 (a)	79,125	$43.50	65,775	$43.50

(a) The weighted average remaining contractual life is one year for all outstanding options as of December 31, 2015.

Summary of Stock Options

The following table summarizes information about stock options for the years ended December 31, 2015 and 2014:



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Aggregate intrinsic value (a)
Options outstanding	$2	$5	$1	$4
Options exercised	3	4	3	3
Cash received by Con Edison for payment of exercise price	6	11	5	8

(a) Aggregate intrinsic value represents the changes in the fair value of all outstanding options from their grant dates to December 31 of the years presented above.

Assumptions Used to Calculate Fair Value

The assumptions used to calculate the fair value of the awards were as follows:



	2015	2014	2013
Risk-free interest rate (a)	0.64% - 3.28%	0.23% - 3.07%	0.13% - 5.17%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	15.82%	13.14%	13.52%


(a)	The risk-free rate is based on the U.S. Treasury zero-coupon yield curve on the date of grant.


(b)	The expected term of the Performance RSUs equals the vesting period. The Companies do not expect significant forfeitures to occur.


(c)	The expected volatility is calculated using daily closing stock prices over a period of three years, which approximates the expected term of the awards.

Summary of Changes in Status of Time-Based Awards

A summary of changes in the status of time-based awards during the year ended December 31, 2015 is as follows:



	Con Edison		CECONY
	Units	Weighted Average Grant Date Fair Value	Units	Weighted Average Grant Date Fair Value
Non-vested at December 31, 2014	65,423	$57.65	62,173	$57.64
Granted	23,000	61.00	21,800	61.00
Vested	(20,773)	58.42	(19,773)	58.42
Forfeited	(2,670)	58.35	(2,570)	58.39
Non-vested at December 31, 2015	64,980	$58.56	61,630	$58.55

TSR and Non TSR Portios

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Summary of Changes in Status of Performance RSUs'

A summary of changes in the status of the Performance RSUs’ TSR and non-TSR portions during the year ended December 31, 2015 is as follows:



	Con Edison			CECONY
		Weighted Average Grant Date Fair Value (a)			Weighted Average Grant Date Fair Value (a)
	Units	TSR Portion (b)	Non-TSR Portion (c)	Units	TSR Portion (b)	Non-TSR Portion (c)
Non-vested at December 31, 2014	1,100,607	$42.33	$56.61	880,523	$42.58	$56.70
Granted	363,900	57.67	63.22	288,669	57.22	63.12
Vested	(327,536)	49.45	58.84	(266,683)	49.34	58.83
Forfeited	(58,632)	43.84	58.25	(49,252)	43.54	58.14
Non-vested at December 31, 2015	1,078,339	$45.26	$58.08	853,257	$45.37	$58.12


(a)	The TSR and non-TSR Portions each account for 50 percent of the awards’ value.


(b)	Fair value is determined using the Monte Carlo simulation described above. Weighted average grant date fair value does not reflect any accrual or payment of dividends prior to vesting.


(c)	Fair value is determined using the market price of one share of Con Edison common stock on the grant date. The market price has not been discounted to reflect that dividends do not accrue and are not payable on Performance RSUs until vesting.

Financial Information by Business Segment (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Financial Data for Business Segments

The financial data for the business segments are as follows:



As of and for the Year Ended December 31, 2015 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)	Construction expenditures
CECONY
Electric	$8,172	$18		$820	$1,798	$447	$447	$30,603	$1,658
Gas	1,527	6		142	356	96	100	6,974	671
Steam	629	86		78	93	41	41	2,653	106
Consolidation adjustments	—	(110)		—	—	—	—	—	—
Total CECONY	$10,328		$—	$1,040	$2,247	$584	$588	$40,230	$2,435
O&R
Electric	$663		$—	$50	$103	$23	$31	$2,140	$114
Gas	182	—		18	18	12	2	579	46
Other (b)	—	—		—	—	—	—	—	—
Total O&R	$845		$—	$68	$121	$35	$33	$2,719	$160
Competitive energy businesses	$1,383	$(2)		$22	$58	$11	$22	$1,680	$823
Other (c)	(2)	2		—	1	23	1	1,013	—
Total Con Edison	$12,554		$—	$1,130	$2,427	$653	$644	$45,642	$3,418



As of and for the Year Ended December 31, 2014 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)(d)	Construction expenditures
CECONY
Electric	$8,437	$16		$781	$1,712	$412	$425	$30,295	$1,500
Gas	1,721	6		132	314	89	88	6,478	549
Steam	628	84		78	113	36	49	2,670	83
Consolidation adjustments	—	(106)		—	—	—	—	—	—
Total CECONY	$10,786		$—	$991	$2,139	$537	$562	$39,443	$2,132
O&R
Electric	$680		$—	$46	$103	$24	$29	$2,023	$105
Gas	212	—		15	25	10	6	786	37
Other (b)	—	—		—	—	1	—	1	—
Total O&R	$892		$—	$61	$128	$35	$35	$2,810	$142
Competitive energy businesses	$1,244	$(10)		$19	$(60)	$(8)	$(8)	$1,013	$447
Other (c)	(3)	10		—	2	27	—	805	—
Total Con Edison	$12,919		$—	$1,071	$2,209	$591	$589	$44,071	$2,721



As of and for the Year Ended December 31, 2013 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Interest charges	Income taxes on operating income (a)	Total assets (b)(d)	Construction expenditures
CECONY
Electric	$8,131	$16		$749	$1,595	$402	$380	$27,547	$1,471
Gas	1,616	5		130	362	83	112	5,977	536
Steam	683	82		67	103	36	39	2,571	128
Consolidation adjustments	—	(103)		—	—	—	—	—	—
Total CECONY	$10,430		$—	$946	$2,060	$521	$531	$36,095	$2,135
O&R
Electric	$628		$—	$41	$87	$25	$13	$1,882	$98
Gas	205	—		15	33	11	7	640	37
Other (b)	—	—		—	—	1	—	2	—
Total O&R	$833		$—	$56	$120	$37	$20	$2,524	$135
Competitive energy businesses	$1,096	$5		$23	$63	$135	$(41)	$1,305	$378
Other (c)	(5)	(5)		(1)	1	26	(6)	527	—
Total Con Edison	$12,354		$—	$1,024	$2,244	$719	$504	$40,451	$2,648


(a)	For Con Edison, the income tax expense on non-operating income was $40 million, $21 million and $28 million in 2015, 2014 and 2013, respectively. For CECONY, the income tax expense on non-operating income was $14 million, $7 million and $11 million in 2015, 2014 and 2013, respectively.


(b)	Includes amounts related to the RECO securitization.


(c)	Parent company, consolidation adjustments and Con Edison Transmission. Other does not represent a business segment.


(d)	Reflects $237 million and $196 million in 2014 and 2013, respectively, related to the adoption of ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” See Notes C and L.

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting Liabilities

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2015 and 2014 were:



(Millions of Dollars)	2015				2014
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$59	$(41)	$18	(b)	$111	$(67)	$44	(b)
Current - assets held for sale (c)	51	(50)	1		—	—	—
Noncurrent	57	(54)	3		34	(23)	11
Noncurrent - assets held for sale (c)	15	(15)	—		—	—	—
Total fair value of derivative assets	$182	$(160)	$22		$145	$(90)	$55
Fair value of derivative liabilities
Current	$(144)	$78	$(66)		$(242)	$139	$(103)
Current - liabilities held for sale (c)	(115)	50	(65)		—	—	—
Noncurrent	(102)	63	(39)		(66)	91	25
Noncurrent - liabilities held for sale (c)	(28)	15	(13)		—	—	—
Total fair value of derivative liabilities	$(389)	$206	$(183)		$(308)	$230	$(78)
Net fair value derivative assets/(liabilities)	$(207)	$46	$(161)	(b)	$(163)	$140	$(23)	(b)
CECONY
Fair value of derivative assets
Current	$40	$(32)	$8	(b)	$26	$(15)	$11	(b)
Noncurrent	48	(47)	1		22	(20)	2
Total fair value of derivative assets	$88	$(79)	$9		$48	$(35)	$13
Fair value of derivative liabilities
Current	$(121)	$71	$(50)		$(96)	$48	$(48)
Noncurrent	(92)	56	(36)		(42)	32	(10)
Total fair value of derivative liabilities	$(213)	$127	$(86)		$(138)	$80	$(58)
Net fair value derivative assets/(liabilities)	$(125)	$48	$(77)	(b)	$(90)	$45	$(45)	(b)

(a)

(b)


(c)	Amounts represent derivative assets and liabilities included in assets and liabilities held for sale on the consolidated balance sheet (see Note U).

Offsetting Assets

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2015 and 2014 were:



(Millions of Dollars)	2015				2014
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$59	$(41)	$18	(b)	$111	$(67)	$44	(b)
Current - assets held for sale (c)	51	(50)	1		—	—	—
Noncurrent	57	(54)	3		34	(23)	11
Noncurrent - assets held for sale (c)	15	(15)	—		—	—	—
Total fair value of derivative assets	$182	$(160)	$22		$145	$(90)	$55
Fair value of derivative liabilities
Current	$(144)	$78	$(66)		$(242)	$139	$(103)
Current - liabilities held for sale (c)	(115)	50	(65)		—	—	—
Noncurrent	(102)	63	(39)		(66)	91	25
Noncurrent - liabilities held for sale (c)	(28)	15	(13)		—	—	—
Total fair value of derivative liabilities	$(389)	$206	$(183)		$(308)	$230	$(78)
Net fair value derivative assets/(liabilities)	$(207)	$46	$(161)	(b)	$(163)	$140	$(23)	(b)
CECONY
Fair value of derivative assets
Current	$40	$(32)	$8	(b)	$26	$(15)	$11	(b)
Noncurrent	48	(47)	1		22	(20)	2
Total fair value of derivative assets	$88	$(79)	$9		$48	$(35)	$13
Fair value of derivative liabilities
Current	$(121)	$71	$(50)		$(96)	$48	$(48)
Noncurrent	(92)	56	(36)		(42)	32	(10)
Total fair value of derivative liabilities	$(213)	$127	$(86)		$(138)	$80	$(58)
Net fair value derivative assets/(liabilities)	$(125)	$48	$(77)	(b)	$(90)	$45	$(45)	(b)

(a)

(b)


(c)	Amounts represent derivative assets and liabilities included in assets and liabilities held for sale on the consolidated balance sheet (see Note U).

Realized and Unrealized Gains or Losses on Commodity Derivatives

The following table presents the realized and unrealized gains or losses on commodity derivatives that have been deferred or recognized in earnings for the years ended December 31, 2015 and 2014:



		Con Edison				CECONY
(Millions of Dollars)	Balance Sheet Location	2015		2014		2015			2014
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$1		$(10)		$2			$(7)
Noncurrent	Deferred derivative gains	1		1		—			1
Total deferred gains/(losses)		$2		$(9)		$2			$(6)
Current	Deferred derivative losses	$(16)		$(75)		$(11)			$(70)
Current	Recoverable energy costs	(136)		36		(127)			26
Noncurrent	Deferred derivative losses	(25)		(17)		(23)			(17)
Total deferred gains/(losses)		$(177)		$(56)		$(161)			$(61)
Net deferred gains/(losses)		$(175)		$(65)		$(159)			$(67)
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Purchased power expense	$(109)	(a)	$(37)	(b)		$—			$—
	Gas purchased for resale	(106)		(115)		—			—
	Non-utility revenue	30	(a)	29	(b)	—			—
	Other operations and maintenance expense	(1)	(c)	—		(1)		(c)	—
Total pre-tax gain/(loss) recognized in income		$(186)		$(123)		$(1)				$—


(a)	For the year ended December 31, 2015, Con Edison recorded unrealized pre-tax gains and losses in non-utility operating revenue ($1 million gain) and purchased power expense ($1 million loss).


(b)	For the year ended December 31, 2014, Con Edison recorded unrealized pre-tax gains and losses in non-utility operating revenue ($4 million gain) and purchased power expense ($132 million loss).


(c)	For the year ended December 31, 2015, Con Edison and CECONY recorded an unrealized loss in other operations and maintenance expense ($1 million).

Hedged Volume of Derivative Transactions

The following table presents the hedged volume of Con Edison’s and CECONY’s derivative transactions at December 31, 2015:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison (c)	37,036,264	21,174	50,052,794	3,696,000
CECONY	18,742,050	12,000	47,540,000	3,696,000


(a)	Volumes are reported net of long and short positions, except natural gas collars where the volumes of long positions are reported.


(b)	Excludes electric congestion and gas basis swap contracts which are associated with electric and gas contracts and hedged volumes.


(c)	Includes 16,381,544 MWh for electric energy, 7,262 MW for capacity and 580,362 Dt for natural gas derivative transactions that are held for sale.

Aggregate Fair Value of Companies' Derivative Instruments with Credit-Risk-Related Contingent Features



(Millions of Dollars)	Con Edison (a)	CECONY (a)
Aggregate fair value – net liabilities	$106	$81
Collateral posted	18	17
Additional collateral (b) (downgrade one level from current ratings)	9	6
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	142	104

(a)

(b)


(c)	Derivative instruments that are net assets have been excluded from the table. At December 31, 2015, if Con Edison had been downgraded to below investment grade, it would have been required to post additional collateral for such derivative instruments of $6 million.

- Definition

Tabular disclosure of credit derivatives which includes information by sellers of credit derivatives, about each credit derivative, or each group of similar credit derivatives, including (a) the nature of the credit derivative - its term, how it arose, the events or circumstances that would require the seller to perform under the credit derivative, and the current status of the payment/performance risk of the credit derivative; (b) the maximum potential amount of future payments (undiscounted) the seller could be required to make under the credit derivative; (c) the current fair value of the credit derivative; and (d) the nature of any recourse provisions under the credit derivative, and any assets held either as collateral or by third parties. A credit derivative is a derivative instrument (1) in which one or more of its underlyings are related to the credit risk of a specified entity (or a group of entities) or an index based on the credit risk of a group of entities and (2) that exposes the seller to potential loss from credit-risk-related events specified in the contract. Examples of credit derivatives within the scope of this paragraph include, but are not limited to, credit default swaps, credit spread options, and credit index products; also includes a hybrid instrument that has an embedded credit derivative (for example, but not limited to, a credit-linked note).

+ References + Details

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41641-113959

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
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-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

Assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2015 and 2014 are summarized below.



	2015						2014
(Millions of Dollars)	Level 1	Level 2	Level 3		Netting Adjustment (e)	Total	Level 1	Level 2	Level 3		Netting Adjustment (e)	Total
Con Edison
Derivative assets:
Commodity (a)(b)(c)	$2	$25	$13		$7	$47	$3	$78	$28		$(27)	$82
Commodity held for sale (f)	—	63	1		(63)	1	—	—	—		—	—
Other (a)(b)(d)	185	112	—		—	297	163	116	—		—	279
Total assets	$187	$200	$14		$(56)	$345	$166	$194	$28		$(27)	$361
Derivative liabilities:
Commodity (a)(b)(c)	$16	$153	$1		$(65)	$105	$18	$246	$8		$(194)	$78
Commodity held for sale (f)	1	133	7		(63)	78	—	—	—		—	—
Total liabilities	$17	$286	$8		$(128)	$183	$18	$246	$8		$(194)	$78
CECONY
Derivative assets:
Commodity (a)(b)(c)	$1	$9	$8		$17	$35	$1	$3	$13		$21	$38
Other (a)(b)(d)	171	105	—		—	276	155	106	—		—	261
Total assets	$172	$114	$8		$17	$311	$156	$109	$13		$21	$299
Derivative liabilities:
Commodity (a)(b)(c)	$14	$129		$—	$(57)	$86	$16	$91		$—	$(49)	$58


(a)	The Companies’ policy is to review the fair value hierarchy and recognize transfers into and transfers out of the levels at the end of each reporting period. There were no transfers between levels 1, 2 and 3 for the years ended December 31, 2015 and 2014.

(b)

(c)


(d)	Other assets are comprised of assets such as life insurance contracts within the deferred compensation plan and non-qualified retirement plans.


(e)	Amounts represent the impact of legally-enforceable master netting agreements that allow the Companies to net gain and loss positions and cash collateral held or placed with the same counterparties.


(f)	Amounts represent derivative assets and liabilities included in Assets and Liabilities held for sale on the consolidated balance sheet (see Note U).

Schedule of Commodity Derivatives

The risk management group reports to the Companies’ Vice President and Treasurer.



	Fair Value of Level 3 at December 31, 2015
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(5)	Discounted Cash Flow	Forward energy prices (a)	$18.33-$77.50 per MWh
		Discounted Cash Flow	Forward capacity prices (a)	$1.17-$7.50 per kW-month
Natural Gas	1	Discounted Cash Flow	Forward natural gas prices (a)	$(7.60) - $5.55 per Dt
Transmission Congestion Contracts/Financial Transmission Rights	10	Discounted Cash Flow	Discount to adjust auction prices for inter-zonal forward price curves (b)	40.8%-62.1%
			Discount to adjust auction prices for historical monthly realized settlements (b)	37.5%-82.2%
			Inter-zonal forward price curves adjusted for historical zonal losses (b)	$(6.35)-$5.59 per MWh
Total Con Edison — Commodity	$6
CECONY — Commodity
Transmission Congestion Contracts	$8	Discounted Cash Flow	Discount to adjust auction prices for inter-zonal forward price curves (b)	40.8%-62.1%
			Discount to adjust auction prices for historical monthly realized settlements (b)	37.5%-82.2%


(a)	Generally, increases/(decreases) in this input in isolation would result in a higher/(lower) fair value measurement.


(b)	Generally, increases/(decreases) in this input in isolation would result in a lower/(higher) fair value measurement.

Reconciliation of Beginning and Ending Net Balances for Assets and Liabilities Measured at Level 3 Fair Value



	Con Edison		CECONY
(Millions of Dollars)	2015	2014	2015	2014
Beginning balance as of January 1,	$20	$9	$13	$6
Included in earnings	(20)	30	(6)	2
Included in regulatory assets and liabilities	1	7	—	7
Purchases	11	22	5	16
Settlements	(6)	(48)	(4)	(18)
Ending balance as of December 31,	$6	$20	$8	$13

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Sale and Resultant Deconsolidation

The following table summarizes the sale and resultant deconsolidation on the transaction date:



(Millions of Dollars)
Proceeds from sale, net of transaction costs of $1	$108
Non-utility property, less accumulated depreciation	(341)
Other assets, including working capital	(31)
Long-term debt, including current portion	217
Other liabilities	9
Gain on sale of solar electric production projects	(45)
Equity method investment upon deconsolidation	$(83)

At December 31, 2015, the carrying amounts of the assets and liabilities designated as held for sale were as follows:



(Millions of Dollars)	Retail Electric Supply Business		Pike		Total
Cash and temporary cash investments		$—	$4		$4
Accounts receivable, less allowance for uncollectible accounts of $8	64		—		64
Accrued unbilled revenue	64		1		65
Other assets	2		1		3
Total current assets	130		6		136
Utility plant, less accumulated depreciation of $6	—		14		14
Non-utility property, less accumulated depreciation of $13	4		—		4
Regulatory assets	—		3		3
Total assets held for sale	$134		$23		$157

Fair value of derivative liabilities	$65			$—	$65
Accounts payable	5		—		5
Other	1		2		3
Total current liabilities	71		2		73
Fair value of derivative liabilities	13		—		13
Long-term debt	—		3		3
Total liabilities held for sale	$84		$5		$89

Schedule of Business Acquisitions, by Acquisition



(Millions of Dollars)	2015	2014
Restricted cash	$9	$13
Receivable from parent company	32	—
Non-utility property, less accumulated depreciation of $5 and $1, respectively	107	108
Other assets	11	14
Total assets (a)	$159	$135
Long-term debt due within one year	$2	$66
Other liabilities	37	11
Long-term debt	62	—
Total liabilities (b)	$101	$77


(a)	The assets of Texas Solar 4 represent assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE.


(b)	The liabilities of Texas Solar 4 represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

Summary of VIEs

The following table summarizes the VIEs in which Con Edison Development has entered into as of December 31, 2015:



Project Name (a)	Generating Capacity (b) (MW AC)	Power Purchase Agreement Term in Years	Year of Initial Investment	Location	Maximum Exposure to Loss (Millions of Dollars) (c)
Copper Mountain Solar 3	128	20	2014	Nevada	$189
Panoche Valley	124	20	2015	California	114
Mesquite Solar 1	83	20	2013	Arizona	110
Copper Mountain Solar 2	75	25	2013	Nevada	85
California Solar	55	25	2012	California	75
Broken Bow II	38	25	2014	Nebraska	55
Pilesgrove	9	n/a (d)	2010	New Jersey	26
Texas Solar 4	32	25	2014	Texas	17


(a)	With the exception of Texas Solar 4, Con Edison’s ownership interest is 50 percent and these projects are accounted for using the equity method of accounting. Con Edison is not the primary beneficiary since the power to direct the activities that most significantly impact the economics of the entities are shared equally between Con Edison Development and third parties.


(b)	Represents Con Edison Development’s ownership interest in the project.

(c)


(d)	Pilesgrove has 3-5 year Solar Renewable Energy Credit hedges in place.

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

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+ Details

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Assets Held for Sale (Tables)

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Assets and Liabilities Designated as Held for Sale

The following table summarizes the sale and resultant deconsolidation on the transaction date:



(Millions of Dollars)
Proceeds from sale, net of transaction costs of $1	$108
Non-utility property, less accumulated depreciation	(341)
Other assets, including working capital	(31)
Long-term debt, including current portion	217
Other liabilities	9
Gain on sale of solar electric production projects	(45)
Equity method investment upon deconsolidation	$(83)

At December 31, 2015, the carrying amounts of the assets and liabilities designated as held for sale were as follows:



(Millions of Dollars)	Retail Electric Supply Business		Pike		Total
Cash and temporary cash investments		$—	$4		$4
Accounts receivable, less allowance for uncollectible accounts of $8	64		—		64
Accrued unbilled revenue	64		1		65
Other assets	2		1		3
Total current assets	130		6		136
Utility plant, less accumulated depreciation of $6	—		14		14
Non-utility property, less accumulated depreciation of $13	4		—		4
Regulatory assets	—		3		3
Total assets held for sale	$134		$23		$157

Fair value of derivative liabilities	$65			$—	$65
Accounts payable	5		—		5
Other	1		2		3
Total current liabilities	71		2		73
Fair value of derivative liabilities	13		—		13
Long-term debt	—		3		3
Total liabilities held for sale	$84		$5		$89

- Definition

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+ Details

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Annual aggregate depreciation allowance	$ 1,110,000,000	$ 1,110,000,000
Impairment charges			$ 0	$ 0
Revenue deferral period (months)		12 months
Investment gains and losses recognized, time period (years)		15 years
Other actuarial gains and losses recognized, time period (years)		10 years
Difference between fair value and expected market related value of plan assets (percent)		20.00%
Non Utility Plan \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		3 years
Non Utility Plan \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		30 years
CECONY
Summary Of Significant Accounting Policies [Line Items]
AFUDC rates (percent)		4.40%	1.60%	4.00%
Average depreciation rates (percent)		3.10%	3.10%	3.20%
Annual aggregate depreciation allowance	1,050,000,000	$ 1,050,000,000
CECONY \| Electric \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
CECONY \| Electric \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		85 years
CECONY \| Gas \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
CECONY \| Gas \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		85 years
CECONY \| Steam \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
CECONY \| Steam \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		80 years
CECONY \| General Plant \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
CECONY \| General Plant \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		55 years
O&R
Summary Of Significant Accounting Policies [Line Items]
AFUDC rates (percent)		0.40%	2.60%	5.70%
Average depreciation rates (percent)		3.00%	2.90%	2.80%
O&R \| Electric \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
O&R \| Electric \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		75 years
O&R \| Gas \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
O&R \| Gas \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		75 years
O&R \| General Plant \| Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		5 years
O&R \| General Plant \| Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives (years)		50 years
Discontinued Operations, Held-for-sale \| Pike
Summary Of Significant Accounting Policies [Line Items]
Impairment charge on assets held for sale	$ 5,000,000	$ 5,000,000

Summary of Significant Accounting Policies - Capitalized Cost of Utility Plant (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
General	$ 2,622	$ 2,465
Held for future use	77	76
Construction work in progress	1,003	1,031
Net Utility Plant	31,133	29,326
Electric Generation
Public Utility, Property, Plant and Equipment [Line Items]
Generation	459	451
Electric
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	3,045	2,956
Electric Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	17,244	16,361
Gas
Public Utility, Property, Plant and Equipment [Line Items]
Gas	5,698	5,006
Steam
Public Utility, Property, Plant and Equipment [Line Items]
Steam	1,849	1,795
General
Public Utility, Property, Plant and Equipment [Line Items]
General	1,758	1,650
CECONY
Public Utility, Property, Plant and Equipment [Line Items]
General	2,411	2,265
Held for future use	65	65
Construction work in progress	922	971
Net Utility Plant	29,310	27,585
CECONY \| Electric Generation
Public Utility, Property, Plant and Equipment [Line Items]
Generation	459	451
CECONY \| Electric
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	2,833	2,744
CECONY \| Electric Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	16,394	15,531
CECONY \| Gas
Public Utility, Property, Plant and Equipment [Line Items]
Gas	5,196	4,530
CECONY \| Steam
Public Utility, Property, Plant and Equipment [Line Items]
Steam	1,849	1,795
CECONY \| General
Public Utility, Property, Plant and Equipment [Line Items]
General	$ 1,592	$ 1,498

Summary of Significant Accounting Policies - Research and Development Costs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Research and Development Expenses [Line Items]
Research and development costs	$ 23	$ 22	$ 18
CECONY
Research and Development Expenses [Line Items]
Research and development costs	$ 22	$ 20	$ 16

Summary of Significant Accounting Policies - Earnings Per Common Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net income	$ 1,193	$ 1,092	$ 1,062
Weighted average common shares outstanding – basic (shares)	293.0	292.9	292.9
Add: Incremental shares attributable to effect of potentially dilutive securities (shares)	1.4	1.1	1.5
Adjusted weighted average common shares outstanding – diluted (shares)	294.4	294.0	294.4
Net income per common share — basic (dollars per share)	$ 4.07	$ 3.73	$ 3.62
Net income per common share — diluted (dollars per share)	$ 4.05	$ 3.71	$ 3.61

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References + Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Summary of Significant Accounting Policies - Changes in Accumulated Other Comprehensive Income by Component (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning, accumulated OCI, net of taxes	$ (45)	$ (25)
OCI before reclassifications, net of tax of $18 and $4 in 2014 for Con Edison and CECONY and $3 in 2015 for Con Edison	5	(26)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) in 2014 for Con Edison and CECONY and $4 and $1 in 2015 for Con Edison and CECONY	6	6
Total OCI, net of taxes	11	(20)	$ 28
Ending, accumulated OCI, net of taxes	(34)	(45)	(25)
OCI before reclassifications, tax	(3)	18
Amounts reclassified from accumulated OCI related to pension plan liabilities, tax	(4)	(4)
CECONY
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning, accumulated OCI, net of taxes	(11)	(6)
OCI before reclassifications, net of tax of $18 and $4 in 2014 for Con Edison and CECONY and $3 in 2015 for Con Edison	1	(6)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(4) and $(1) in 2014 for Con Edison and CECONY and $4 and $1 in 2015 for Con Edison and CECONY	1	1
Total OCI, net of taxes	2	(5)	3
Ending, accumulated OCI, net of taxes	(9)	(11)	$ (6)
OCI before reclassifications, tax		4
Amounts reclassified from accumulated OCI related to pension plan liabilities, tax	$ (1)	$ (1)

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Regulatory Matters - Additional Information (Detail) - CECONY - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2019	Jan. 31, 2018	Jan. 31, 2016
Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Interim rate increase (decrease), amount	$ 141	$ 180
Interim rate increase (decrease), percent	9.75%	9.75%
Requested equity capital structure, rate increase (decrease) (percent)	48.00%	48.00%
Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Interim rate increase (decrease), amount	$ 109	$ 97
Interim rate increase (decrease), percent	9.75%	9.75%
Requested equity capital structure, rate increase (decrease) (percent)	48.00%	48.00%
Subsequent Event \| Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount			$ 482
Requested return on equity (percent)			9.75%
Requested equity capital structure (percent)			48.00%
Subsequent Event \| Gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount			$ 154
Requested return on equity (percent)			9.75%
Requested equity capital structure (percent)			48.00%

Regulatory Matters - Other Regulatory Matters - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Jan. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Annual electric revenue subject to potential refund		$ 249,000,000
Revenues from gas		32,000,000
Annual steam revenue subject to potential refund		6,000,000
Potential estimated refund to customers		1,962,000,000
Construction expenditures overcharge consultant estimate	$ 208,000,000
Regulatory liability, expected credit to customers		116,000,000
Regulatory liability, return on capital expenditures, not recoverable		55,000,000
Regulatory liabilities		$ 1,977,000,000	$ 1,993,000,000
Net electric deferrals
Public Utilities, General Disclosures [Line Items]
Amortization period (years)		10 years
Prudence proceeding
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities		$ 99,000,000	105,000,000
Net unbilled revenue deferrals
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities		$ 109,000,000	$ 138,000,000

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Electric) (Detail) - USD ($)	1 Months Ended	9 Months Ended	12 Months Ended					36 Months Ended	45 Months Ended
	Apr. 30, 2012	Dec. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2016	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Cost reconciliations, deferred net regulatory liabilities				$ 947,000,000	$ 910,000,000
Cost reconciliations, deferred net regulatory assets				836,000,000	615,000,000
Annual electric revenue subject to potential refund				249,000,000
CECONY
Public Utilities, General Disclosures [Line Items]
Cost reconciliations, deferred net regulatory liabilities				899,000,000	863,000,000
Cost reconciliations, deferred net regulatory assets				752,000,000	574,000,000
Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Retention of annual transmission congestion revenues		$ 90,000,000
Deferred revenues		34,000,000		98,000,000	146,000,000	$ 34,000,000	$ 59,000,000		$ 34,000,000
Negative revenue adjustments					5,000,000	0	0
Cost reconciliations, deferred net regulatory liabilities				26,000,000	$ 57,000,000		$ 146,000,000
Cost reconciliations, deferred net regulatory assets		35,000,000				35,000,000			35,000,000
Deferred regulatory liability (reduction)				17,000,000		7,000,000
Earnings sharing, threshold limit				44,400,000.0		$ 17,500,000.0
Elimination of temporary base rate increase through credits	$ 134,000,000
Base rate change deferral regulatory liability impact				$ 30,000,000
Deferrals for property taxes limitation from rates (percent)				90.00%		80.00%
Recovery deferral (percentage)				80.00%
Maximum deferral (percentage)				30.00%
Deferral, annual maximum (not more than) (percent)				0.10%
Electric \| CECONY \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)									350,000,000
Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities			$ 123,000,000
Electric \| Storm Reserve \| CECONY
Public Utilities, General Disclosures [Line Items]
Revenue requirement				$ 21,000,000
Deferred storm costs \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory asset			107,000,000
Increase (decrease) in recoverable property damage costs			(4,000,000)
Year 1 \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 420,000,000				$ 420,000,000			420,000,000
Amortization to income of net regulatory (assets) and liabilities									(75,300,000)
Retention of annual transmission congestion revenues									120,000,000
Average rate base									$ 14,887,000,000
Weighted average cost of capital (after-tax) (percent)									7.76%
Authorized return on common equity (percent)									10.15%
Authorized return on common equity, austerity measures									$ 27,000,000
Earnings sharing (percentage)		11.15%				11.15%			11.15%
Cost of long-term debt (percent)		5.65%				5.65%			5.65%
Common equity ratio (percent)									48.00%
Year 1 \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes			$ (76,200,000)					$ (76,200,000)
Amortization to income of net regulatory (assets) and liabilities								(37,000,000)
Retention of annual transmission congestion revenues								90,000,000
Average rate base								$ 17,323,000,000
Weighted average cost of capital (after-tax) (percent)								7.05%
Authorized return on common equity (percent)								9.20%
Earnings sharing (percentage)			9.80%					9.80%
Cost of long-term debt (percent)			5.17%					5.17%
Common equity ratio (percent)								48.00%
Year 1 \| Electric \| CECONY \| Scenario, Forecast \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)								$ 400,000,000
Year 1 \| Transmission and distribution \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									$ 13,818,000,000
Year 1 \| Transmission and distribution \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								16,869,000,000
Year 1 \| Storm hardening \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								89,000,000
Year 1 \| Other \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									1,487,000,000
Year 1 \| Other \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								2,034,000,000
Year 2 \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 420,000,000				$ 420,000,000			420,000,000
Amortization to income of net regulatory (assets) and liabilities									(75,300,000)
Retention of annual transmission congestion revenues									120,000,000
Average rate base									$ 15,987,000,000
Weighted average cost of capital (after-tax) (percent)									7.76%
Authorized return on common equity (percent)									10.15%
Authorized return on common equity, austerity measures									$ 20,000,000
Earnings sharing (percentage)		10.65%				10.65%			10.65%
Cost of long-term debt (percent)		5.65%				5.65%			5.65%
Common equity ratio (percent)									48.00%
Year 2 \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes			$ 124,000,000					124,000,000
Amortization to income of net regulatory (assets) and liabilities								(37,000,000)
Retention of annual transmission congestion revenues								90,000,000
Average rate base								$ 18,113,000,000
Weighted average cost of capital (after-tax) (percent)								7.08%
Authorized return on common equity (percent)								9.20%
Earnings sharing (percentage)			9.80%					9.80%
Cost of long-term debt (percent)			5.23%					5.23%
Common equity ratio (percent)								48.00%
Year 2 \| Transmission and distribution \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									$ 14,742,000,000
Year 2 \| Transmission and distribution \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								$ 17,401,000,000
Year 2 \| Enterprise resource project \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									25,000,000
Year 2 \| Storm hardening \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								177,000,000
Year 2 \| Other \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									1,565,000,000
Year 2 \| Other \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								2,012,000,000
Year 3 \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 287,000,000				$ 287,000,000			287,000,000
Amortization to income of net regulatory (assets) and liabilities									(75,300,000)
Retention of annual transmission congestion revenues									120,000,000
Average rate base									$ 16,826,000,000
Weighted average cost of capital (after-tax) (percent)									7.76%
Authorized return on common equity (percent)									10.15%
Authorized return on common equity, austerity measures									$ 13,000,000
Earnings sharing (percentage)		10.65%				10.65%			10.65%
Cost of long-term debt (percent)		5.65%				5.65%			5.65%
Common equity ratio (percent)									48.00%
Year 3 \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes			$ 0					0
Amortization to income of net regulatory (assets) and liabilities			$ 123,000,000
Average rate base								$ 18,282,000,000
Weighted average cost of capital (after-tax) (percent)								6.91%
Authorized return on common equity (percent)								9.00%
Earnings sharing (percentage)			9.60%					9.60%
Cost of long-term debt (percent)			5.09%					5.09%
Common equity ratio (percent)								48.00%
Year 3 \| Transmission and distribution \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									$ 15,414,000,000
Year 3 \| Transmission and distribution \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								$ 17,929,000,000
Year 3 \| Enterprise resource project \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									115,000,000
Year 3 \| Storm hardening \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								268,000,000
Year 3 \| Other \| Electric \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)									$ 1,650,000,000
Year 3 \| Other \| Electric \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)								$ 2,069,000,000

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Gas) (Detail) - USD ($)	12 Months Ended					36 Months Ended	39 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2016	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Cost reconciliation, deferred net regulatory assets		$ 836,000,000	$ 615,000,000
Cost reconciliations, deferred net regulatory liabilities		947,000,000	910,000,000
Revenues from gas		32,000,000
CECONY
Public Utilities, General Disclosures [Line Items]
Cost reconciliation, deferred net regulatory assets		752,000,000	574,000,000
Cost reconciliations, deferred net regulatory liabilities		$ 899,000,000	$ 863,000,000
Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Percentage of revenue reserve		15.00%	15.00%	25.00%	25.00%
Amount of revenues retained		$ 66,000,000	$ 70,000,000	$ 64,000,000	$ 57,000,000		$ 64,000,000
Deferred revenues		54,000,000	28,000,000	36,000,000	22,000,000		36,000,000
Negative revenue adjustments		0	0	0	0
Cost reconciliation, deferred net regulatory assets				26,000,000	9,000,000		26,000,000
Cost reconciliations, deferred net regulatory liabilities		11,000,000	38,000,000
Net utility plant reconciliations		1,000,000	0	9,500,000	2,900,000
Authorized return on common equity, austerity measures				$ 2,000,000	4,000,000
Earnings sharing, threshold limit		$ 0	0
Difference in property taxes (percent)		90.00%		80.00%
Deferral, annual maximum (not more than) (percent)		0.10%
Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Other regulatory liabilities	$ 32,000,000					$ 32,000,000
Gas \| CECONY \| Maximum
Public Utilities, General Disclosures [Line Items]
Amount of revenues retained		$ 65,000,000	65,000,000	$ 58,000,000	$ 58,000,000		58,000,000
Potential Penalties (annually) (up to)		$ 44,000,000	$ 33,000,000				12,600,000.0
Gas \| CECONY \| Maximum \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)	$ 56,000,000
Year 1 \| Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes							47,000,000
Amortization to income of net regulatory (assets) and liabilities							(53,100,000)
Average rate base							$ 3,027,000,000
Weighted average cost of capital (after-tax) (percent)							7.46%
Authorized return on common equity (percent)							9.60%
Earnings sharing (percentage)				10.35%			10.35%
Cost of long-term debt (percent)				5.57%			5.57%
Common equity ratio (percent)							48.00%
Year 1 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes						(54,600,000)
Amortization to income of net regulatory (assets) and liabilities						4,000,000
Average rate base						$ 3,521,000,000
Weighted average cost of capital (after-tax) (percent)						7.10%
Authorized return on common equity (percent)						9.30%
Earnings sharing (percentage)	9.90%					9.90%
Cost of long-term debt (percent)	5.17%					5.17%
Common equity ratio (percent)						48.00%
Year 2 \| Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 48,000,000
Amortization to income of net regulatory (assets) and liabilities							(53,100,000)
Average rate base							$ 3,245,000,000
Weighted average cost of capital (after-tax) (percent)							7.46%
Authorized return on common equity (percent)							9.60%
Earnings sharing (percentage)				10.15%			10.15%
Cost of long-term debt (percent)				5.57%			5.57%
Common equity ratio (percent)							48.00%
Year 2 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 38,600,000
Amortization to income of net regulatory (assets) and liabilities						4,000,000
Average rate base						$ 3,863,000,000
Weighted average cost of capital (after-tax) (percent)						7.13%
Authorized return on common equity (percent)						9.30%
Earnings sharing (percentage)	9.90%					9.90%
Cost of long-term debt (percent)	5.23%					5.23%
Common equity ratio (percent)						48.00%
Year 3 \| Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 47,000,000
Amortization to income of net regulatory (assets) and liabilities							(53,100,000)
Average rate base							$ 3,434,000,000
Weighted average cost of capital (after-tax) (percent)							7.46%
Authorized return on common equity (percent)							9.60%
Earnings sharing (percentage)				10.15%			10.15%
Cost of long-term debt (percent)				5.57%			5.57%
Common equity ratio (percent)							48.00%
Year 3 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 56,800,000
Amortization to income of net regulatory (assets) and liabilities						4,000,000
Average rate base						$ 4,236,000,000
Weighted average cost of capital (after-tax) (percent)						7.21%
Authorized return on common equity (percent)						9.30%
Earnings sharing (percentage)	9.90%					9.90%
Cost of long-term debt (percent)	5.39%					5.39%
Common equity ratio (percent)						48.00%
Gas Delivery \| Year 1 \| Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 2,934,000,000
Gas Delivery \| Year 1 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						$ 3,899,000,000
Gas Delivery \| Year 2 \| Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							3,148,000,000
Gas Delivery \| Year 2 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						4,258,000,000
Gas Delivery \| Year 3 \| Gas \| CECONY
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 3,346,000,000
Gas Delivery \| Year 3 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						4,698,000,000
Storm hardening \| Year 1 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						3,000,000
Storm hardening \| Year 2 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						8,000,000
Storm hardening \| Year 3 \| Gas \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						$ 30,000,000

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Steam) (Detail) - USD ($)	12 Months Ended				36 Months Ended	39 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2016	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Cost reconciliation, deferred net regulatory liabilities	$ 947,000,000	$ 910,000,000
Cost reconciliations, deferred net regulatory assets	836,000,000	615,000,000
CECONY
Public Utilities, General Disclosures [Line Items]
Cost reconciliation, deferred net regulatory liabilities	899,000,000	863,000,000
Cost reconciliations, deferred net regulatory assets	752,000,000	574,000,000
Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Negative revenue adjustments	0	0	$ 0	$ 0
Cost reconciliation, deferred net regulatory liabilities		42,000,000	17,000,000	12,000,000		$ 17,000,000
Cost reconciliations, deferred net regulatory assets	17,000,000
Deferred regulatory liability (reduction)		1,100,000	0	200,000
Authorized return on common equity, austerity measures			2,000,000	$ 3,000,000
Earnings sharing, threshold limit	17,100,000	$ 0	$ 500,000
Potential refund from customers	$ 6,000,000
Difference in property taxes (percent)	90.00%		80.00%
Deferral, annual maximum (not more than) (percent)	0.10%
Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Other regulatory liabilities					$ 8,000,000
Steam \| CECONY \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)						1,000,000
Steam \| CECONY \| Maximum \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)					1,000,000
Year 1 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes						49,500,000
Amortization to income of net regulatory (assets) and liabilities						(20,100,000)
Average rate base						$ 1,589,000,000
Weighted average cost of capital (after-tax) (percent)						7.46%
Authorized return on common equity (percent)						9.60%
Earnings sharing (percentage)			10.35%			10.35%
Cost of long-term debt (percent)			5.57%			5.57%
Common equity ratio (percent)						48.00%
Year 1 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					(22,400,000)
Amortization to income of net regulatory (assets) and liabilities					37,000,000
Average rate base					$ 1,511,000,000
Weighted average cost of capital (after-tax) (percent)					7.10%
Authorized return on common equity (percent)					9.30%
Earnings sharing (percentage)					9.90%
Cost of long-term debt (percent)					5.17%
Common equity ratio (percent)					48.00%
Year 2 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 49,500,000
Amortization to income of net regulatory (assets) and liabilities						(20,100,000)
Average rate base						$ 1,603,000,000
Weighted average cost of capital (after-tax) (percent)						7.46%
Authorized return on common equity (percent)						9.60%
Earnings sharing (percentage)			10.15%			10.15%
Cost of long-term debt (percent)			5.57%			5.57%
Common equity ratio (percent)						48.00%
Year 2 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					$ 19,800,000
Amortization to income of net regulatory (assets) and liabilities					37,000,000
Average rate base					$ 1,547,000,000
Weighted average cost of capital (after-tax) (percent)					7.13%
Authorized return on common equity (percent)					9.30%
Earnings sharing (percentage)					9.90%
Cost of long-term debt (percent)					5.23%
Common equity ratio (percent)					48.00%
Year 3 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 17,800,000
Base rate change through surcharge						31,700,000
Amortization to income of net regulatory (assets) and liabilities						(20,100,000)
Average rate base						$ 1,613,000,000
Weighted average cost of capital (after-tax) (percent)						7.46%
Authorized return on common equity (percent)						9.60%
Earnings sharing (percentage)			10.15%			10.15%
Cost of long-term debt (percent)			5.57%			5.57%
Common equity ratio (percent)						48.00%
Year 3 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					$ 20,300,000
Amortization to income of net regulatory (assets) and liabilities					37,000,000
Average rate base					$ 1,604,000,000
Weighted average cost of capital (after-tax) (percent)					7.21%
Authorized return on common equity (percent)					9.30%
Earnings sharing (percentage)					9.90%
Cost of long-term debt (percent)					5.39%
Common equity ratio (percent)					48.00%
Production \| Year 1 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)						$ 415,000,000
Production \| Year 1 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)					$ 1,752,000,000
Production \| Year 2 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)						426,000,000
Production \| Year 2 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)					1,732,000,000
Production \| Year 3 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)						433,000,000
Production \| Year 3 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)					1,720,000,000
Distribution \| Year 1 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)						521,000,000
Distribution \| Year 1 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)					6,000,000
Distribution \| Year 2 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)						534,000,000
Distribution \| Year 2 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)					11,000,000
Distribution \| Year 3 \| Steam \| CECONY
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)						$ 543,000,000
Distribution \| Year 3 \| Steam \| CECONY \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred regulatory liability (reduction)					$ 25,000,000

Regulatory Matters - Summary of Utilities Rate Plans (O&R New York-Electric) (Detail) - Electric - O&R - USD ($)	12 Months Ended				24 Months Ended	36 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2017	Jun. 30, 2015
Public Utilities, General Disclosures [Line Items]
Deferred revenues		$ (3,400,000)	$ 3,200,000	$ 2,600,000
Negative revenue adjustments	$ 1,250,000.00	0	0	0
Deferral of net increase (decrease) to regulatory assets	1,200,000	(200,000)	4,100,000	7,800,000
Deferred regulatory liability (reduction)	2,200,000	(2,300,000)	$ (1,100,000)	$ 4,200,000
Earnings sharing, threshold limit	$ 0	$ 1,000,000
Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)						$ 3,000,000
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Deferred storm and property reserve deficiency, noncurrent					$ 59,300,000
Deferred storm and property reserve deficiency, recovery period (years)					5 years
Deferred storm and property reserve deficiency not recovered					$ 1,000,000
Scenario, Forecast \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)					4,000,000
Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes						19,400,000
Amortization to income of net regulatory (assets) and liabilities						(32,200,000)
Deferred regulatory liability (reduction)						678,000,000
Average rate base						$ 671,000,000
Weighted average cost of capital (after-tax) (percent)						7.61%
Authorized return on common equity (percent)						9.40%
Cost of long-term debt (percent)						6.07%
Common equity ratio (percent)						48.00%
Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					9,300,000
Amortization to income of net regulatory (assets) and liabilities					(8,500,000)
Deferred regulatory liability (reduction)					928,000,000
Average rate base					$ 763,000,000
Weighted average cost of capital (after-tax) (percent)					7.10%
Authorized return on common equity (percent)					9.00%
Earnings sharing (percentage)					9.60%
Cost of long-term debt (percent)					5.42%
Common equity ratio (percent)					48.00%
Deferred storm and property reserve deficiency, noncurrent					$ 11,850,000
Rate exclusion amount with balance below regulatory threshold					1,000,000
Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 8,800,000
Amortization to income of net regulatory (assets) and liabilities						(32,200,000)
Deferred regulatory liability (reduction)						704,000,000
Average rate base						$ 708,000,000
Weighted average cost of capital (after-tax) (percent)						7.65%
Authorized return on common equity (percent)						9.50%
Cost of long-term debt (percent)						6.07%
Common equity ratio (percent)						48.00%
Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					8,800,000
Amortization to income of net regulatory (assets) and liabilities					(9,400,000)
Deferred regulatory liability (reduction)					970,000,000
Average rate base					$ 805,000,000
Weighted average cost of capital (after-tax) (percent)					7.06%
Authorized return on common equity (percent)					9.00%
Earnings sharing (percentage)					9.60%
Cost of long-term debt (percent)					5.35%
Common equity ratio (percent)					48.00%
Deferred storm and property reserve deficiency, noncurrent					$ 11,850,000
Rate exclusion amount with balance below regulatory threshold					9,000,000
Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 15,200,000
Amortization to income of net regulatory (assets) and liabilities						(32,200,000)
Deferred regulatory liability (reduction)						753,000,000
Average rate base						$ 759,000,000
Weighted average cost of capital (after-tax) (percent)						7.48%
Authorized return on common equity (percent)						9.60%
Cost of long-term debt (percent)						5.64%
Common equity ratio (percent)						48.00%
Property Tax and Interest Rate Reconciliations \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Regulatory assets not recoverable					$ 4,000,000

Regulatory Matters - Summary of Utilities Rate Plans (O&R New York-Gas) (Detail) - USD ($)	12 Months Ended				36 Months Ended	62 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2018	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Cost reconciliations, deferred net regulatory assets	$ 836,000,000	$ 615,000,000				$ 615,000,000
Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Deferred revenues	(800,000)	(100,000)	$ 700,000	$ 4,700,000		(100,000)
Negative revenue adjustments	0	0	0	0
Cost reconciliations, deferred net regulatory assets	2,500,000	8,300,000	8,300,000	700,000		8,300,000
Net utility plant reconciliations	0	0	0	700,000
Earnings sharing, threshold limit	$ 0	$ 0	$ 0	$ 0
Gas \| O&R \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)						1,400,000.0
Scenario, Forecast \| Property Tax and Interest Rate Reconciliations \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Regulatory assets not recoverable					$ 14,000,000
Year 1 \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Base rate changes						9,000,000
Amortization to income of net regulatory (assets) and liabilities						(2,000,000)
Average rate base						$ 280,000,000
Weighted average cost of capital (after-tax) (percent)						8.49%
Authorized return on common equity (percent)						10.40%
Earnings sharing (percentage)		11.40%				11.40%
Cost of long-term debt (percent)		6.81%				6.81%
Common equity ratio (percent)						48.00%
Year 1 \| Scenario, Forecast \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Base rate changes					16,400,000
Amortization to income of net regulatory (assets) and liabilities					(1,700,000)
Average rate base					$ 366,000,000
Weighted average cost of capital (after-tax) (percent)					7.10%
Authorized return on common equity (percent)					9.00%
Earnings sharing (percentage)					9.60%
Cost of long-term debt (percent)					5.42%
Common equity ratio (percent)					48.00%
Rate exclusion amount with balance below regulatory threshold					$ 500,000
Year 1 \| Scenario, Forecast \| Gas \| O&R \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)					3,700,000.0
Net utility plant reconciliations					492,000,000
Year 2 \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 9,000,000
Amortization to income of net regulatory (assets) and liabilities						(2,000,000)
Average rate base						$ 296,000,000
Weighted average cost of capital (after-tax) (percent)						8.49%
Authorized return on common equity (percent)						10.40%
Earnings sharing (percentage)		11.40%				11.40%
Cost of long-term debt (percent)		6.81%				6.81%
Common equity ratio (percent)						48.00%
Year 2 \| Scenario, Forecast \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Base rate changes					16,400,000
Amortization to income of net regulatory (assets) and liabilities					(2,100,000)
Average rate base					$ 391,000,000
Weighted average cost of capital (after-tax) (percent)					7.06%
Authorized return on common equity (percent)					9.00%
Earnings sharing (percentage)					9.60%
Cost of long-term debt (percent)					5.35%
Common equity ratio (percent)					48.00%
Rate exclusion amount with balance below regulatory threshold					$ 4,200,000
Year 2 \| Scenario, Forecast \| Gas \| O&R \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)					4,700,000.0
Net utility plant reconciliations					518,000,000
Year 3 \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ 4,600,000
Base rate change through surcharge						4,300,000
Amortization to income of net regulatory (assets) and liabilities						(2,000,000)
Average rate base						$ 309,000,000
Weighted average cost of capital (after-tax) (percent)						8.49%
Authorized return on common equity (percent)						10.40%
Earnings sharing (percentage)		11.40%				11.40%
Cost of long-term debt (percent)		6.81%				6.81%
Common equity ratio (percent)						48.00%
Year 3 \| Scenario, Forecast \| Gas \| O&R
Public Utilities, General Disclosures [Line Items]
Base rate changes					5,800,000
Base rate change through surcharge					10,600,000
Amortization to income of net regulatory (assets) and liabilities					(2,500,000)
Average rate base					$ 417,000,000
Weighted average cost of capital (after-tax) (percent)					7.06%
Authorized return on common equity (percent)					9.00%
Earnings sharing (percentage)					9.60%
Cost of long-term debt (percent)					5.35%
Common equity ratio (percent)					48.00%
Rate exclusion amount with balance below regulatory threshold					$ 7,200,000
Year 3 \| Scenario, Forecast \| Gas \| O&R \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential Penalties (annually) (up to)					5,800,000.0
Net utility plant reconciliations					$ 546,000,000

Regulatory Matters - Summary of Utilities Rate Plans (Rockland Electric Company (RECO)) (Detail) - Rockland Electric Company (RECO) - USD ($) $ in Millions	1 Months Ended	12 Months Ended	51 Months Ended
	Jan. 31, 2016	Jul. 31, 2015	Jul. 31, 2014
Public Utilities, General Disclosures [Line Items]
Average rate base			$ 148.6
Weighted average cost of capital (after-tax) (percent)			8.21%
Authorized return on common equity (percent)			10.30%
Cost of long-term debt (percent)			6.16%
Common equity ratio (percent)			50.00%
Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 13.0	$ 9.8
Amortization to income of net regulatory (assets) and liabilities		0.4	(3.9)
Deferred major storm costs		(25.6)	(4.9)
Average rate base		$ 172.2	$ 148.6
Weighted average cost of capital (after-tax) (percent)		7.83%	8.21%
Authorized return on common equity (percent)		9.75%	10.30%
Cost of long-term debt (percent)		5.89%	6.16%
Common equity ratio (percent)		50.00%	50.00%
Year 2
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities		$ 0.4	$ (3.9)
Deferred major storm costs		(25.6)	(4.9)
Average rate base		$ 172.2	$ 148.6
Weighted average cost of capital (after-tax) (percent)		7.83%	8.21%
Authorized return on common equity (percent)		9.75%	10.30%
Cost of long-term debt (percent)		5.89%	6.16%
Common equity ratio (percent)		50.00%	50.00%
Year 3
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities		$ 0.4	$ (3.9)
Deferred major storm costs		(25.6)	(4.9)
Average rate base		$ 172.2	$ 148.6
Weighted average cost of capital (after-tax) (percent)		7.83%	8.21%
Authorized return on common equity (percent)		9.75%	10.30%
Cost of long-term debt (percent)		5.89%	6.16%
Common equity ratio (percent)		50.00%	50.00%
Year 4
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities			$ (3.9)
Deferred major storm costs		$ (25.6)	(4.9)
Average rate base		$ 172.2	$ 148.6
Weighted average cost of capital (after-tax) (percent)		7.83%	8.21%
Authorized return on common equity (percent)		9.75%	10.30%
Cost of long-term debt (percent)		5.89%	6.16%
Common equity ratio (percent)		50.00%	50.00%
Year 5
Public Utilities, General Disclosures [Line Items]
Deferred major storm costs			$ (4.9)
Subsequent Event \| Electric
Public Utilities, General Disclosures [Line Items]
RECO plan period (years)	3 years
RECO plan electric system storm hardening amount	$ 15.7

Regulatory Matters - Summary of Utilities Rate Plans (Pike - Electric) (Detail) - Electric - Pike County Light & Power Company (Pike) - USD ($) $ in Thousands	12 Months Ended	65 Months Ended
	Aug. 31, 2015	Aug. 31, 2014
Public Utilities, General Disclosures [Line Items]
Base rate changes	$ 1,250	$ 900
Year 1
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities	(70)	100
Year 2
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities	(70)	100
Year 3
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities	(70)	100
Year 4
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities	(70)	100
Year 5
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities	$ (70)	$ 100

Regulatory Matters - Regulatory Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory assets
Regulatory assets – noncurrent	$ 8,096	$ 9,142
Regulatory assets – current	132	138
Total Regulatory Assets	8,228	9,280
Regulatory liabilities
Regulatory liabilities – noncurrent	1,977	1,993
Regulatory liabilities—current	115	163
Total Regulatory Liabilities	2,092	2,156
Allowance for cost of removal less salvage
Regulatory liabilities
Regulatory liabilities – noncurrent	676	598
Base rate change deferrals
Regulatory liabilities
Regulatory liabilities – noncurrent	128	155
Net unbilled revenue deferrals
Regulatory liabilities
Regulatory liabilities – noncurrent	109	138
Prudence proceeding
Regulatory liabilities
Regulatory liabilities – noncurrent	99	105
Earnings sharing - electric and steam
Regulatory liabilities
Regulatory liabilities – noncurrent	80	19
Pension and other postretirement benefit deferrals
Regulatory liabilities
Regulatory liabilities – noncurrent	76	46
New York State income tax rate change
Regulatory liabilities
Regulatory liabilities – noncurrent	75	62
Variable-rate tax-exempt debt - cost rate reconciliation
Regulatory liabilities
Regulatory liabilities – noncurrent	70	78
Carrying charges on repair allowance and bonus depreciation
Regulatory liabilities
Regulatory liabilities – noncurrent	49	58
Property tax refunds
Regulatory liabilities
Regulatory liabilities – noncurrent	44	87
Net utility plant reconciliations
Regulatory liabilities
Regulatory liabilities – noncurrent	32	21
Unrecognized other postretirement costs
Regulatory liabilities
Regulatory liabilities – noncurrent	28	0
World Trade Center settlement proceeds
Regulatory liabilities
Regulatory liabilities – noncurrent	21	41
Other
Regulatory liabilities
Regulatory liabilities – noncurrent	187	290
Refundable energy costs
Regulatory liabilities
Regulatory liabilities—current	64	128
Revenue decoupling mechanism
Regulatory liabilities
Regulatory liabilities—current	45	30
Deferred derivative gains
Regulatory liabilities
Regulatory liabilities—current	6	5
Unrecognized pension and other postretirement costs
Regulatory assets
Regulatory assets – noncurrent	3,876	4,846
Future income tax
Regulatory assets
Regulatory assets – noncurrent	2,350	2,259
Environmental remediation costs
Regulatory assets
Regulatory assets – noncurrent	904	925
Revenue taxes
Regulatory assets
Regulatory assets – noncurrent	253	219
Deferred storm costs
Regulatory assets
Regulatory assets – noncurrent	185	319
Unamortized loss on reacquired debt
Regulatory assets
Regulatory assets – noncurrent	50	57
Deferred derivative losses
Regulatory assets
Regulatory assets – noncurrent	50	25
O&R property tax reconciliation
Regulatory assets
Regulatory assets – noncurrent	46	36
Pension and other postretirement benefits deferrals
Regulatory assets
Regulatory assets – noncurrent	45	66
Surcharge for New York State assessment
Regulatory assets
Regulatory assets – noncurrent	44	99
Net electric deferrals
Regulatory assets
Regulatory assets – noncurrent	44	63
Preferred stock redemption
Regulatory assets
Regulatory assets – noncurrent	26	27
O&R transition bond charges
Regulatory assets
Regulatory assets – noncurrent	21	27
Recoverable energy costs
Regulatory assets
Regulatory assets – noncurrent	16	19
Regulatory assets – current	19	41
Workers’ compensation
Regulatory assets
Regulatory assets – noncurrent	11	8
Other
Regulatory assets
Regulatory assets – noncurrent	175	147
Deferred derivative losses
Regulatory assets
Regulatory assets – current	113	97
Property tax reconciliation
Regulatory liabilities
Regulatory liabilities – noncurrent	303	295
CECONY
Regulatory assets
Regulatory assets – noncurrent	7,482	8,457
Regulatory assets – current	121	132
Total Regulatory Assets	7,603	8,589
Regulatory liabilities
Regulatory liabilities – noncurrent	1,789	1,837
Regulatory liabilities—current	84	118
Total Regulatory Liabilities	1,873	1,955
CECONY \| Allowance for cost of removal less salvage
Regulatory liabilities
Regulatory liabilities – noncurrent	570	499
CECONY \| Base rate change deferrals
Regulatory liabilities
Regulatory liabilities – noncurrent	128	155
CECONY \| Net unbilled revenue deferrals
Regulatory liabilities
Regulatory liabilities – noncurrent	109	138
CECONY \| Prudence proceeding
Regulatory liabilities
Regulatory liabilities – noncurrent	99	105
CECONY \| Earnings sharing - electric and steam
Regulatory liabilities
Regulatory liabilities – noncurrent	80	18
CECONY \| Pension and other postretirement benefit deferrals
Regulatory liabilities
Regulatory liabilities – noncurrent	46	37
CECONY \| New York State income tax rate change
Regulatory liabilities
Regulatory liabilities – noncurrent	72	59
CECONY \| Variable-rate tax-exempt debt - cost rate reconciliation
Regulatory liabilities
Regulatory liabilities – noncurrent	60	78
CECONY \| Carrying charges on repair allowance and bonus depreciation
Regulatory liabilities
Regulatory liabilities – noncurrent	48	57
CECONY \| Property tax refunds
Regulatory liabilities
Regulatory liabilities – noncurrent	44	87
CECONY \| Net utility plant reconciliations
Regulatory liabilities
Regulatory liabilities – noncurrent	31	20
CECONY \| Unrecognized other postretirement costs
Regulatory liabilities
Regulatory liabilities – noncurrent	28	0
CECONY \| World Trade Center settlement proceeds
Regulatory liabilities
Regulatory liabilities – noncurrent	21	41
CECONY \| Other
Regulatory liabilities
Regulatory liabilities – noncurrent	150	248
CECONY \| Refundable energy costs
Regulatory liabilities
Regulatory liabilities—current	33	84
CECONY \| Revenue decoupling mechanism
Regulatory liabilities
Regulatory liabilities—current	45	30
CECONY \| Deferred derivative gains
Regulatory liabilities
Regulatory liabilities—current	6	4
CECONY \| Unrecognized pension and other postretirement costs
Regulatory assets
Regulatory assets – noncurrent	3,697	4,609
CECONY \| Future income tax
Regulatory assets
Regulatory assets – noncurrent	2,232	2,142
CECONY \| Environmental remediation costs
Regulatory assets
Regulatory assets – noncurrent	800	820
CECONY \| Revenue taxes
Regulatory assets
Regulatory assets – noncurrent	240	208
CECONY \| Deferred storm costs
Regulatory assets
Regulatory assets – noncurrent	110	224
CECONY \| Unamortized loss on reacquired debt
Regulatory assets
Regulatory assets – noncurrent	48	55
CECONY \| Deferred derivative losses
Regulatory assets
Regulatory assets – noncurrent	46	23
CECONY \| Pension and other postretirement benefits deferrals
Regulatory assets
Regulatory assets – noncurrent	16	42
CECONY \| Surcharge for New York State assessment
Regulatory assets
Regulatory assets – noncurrent	40	92
CECONY \| Net electric deferrals
Regulatory assets
Regulatory assets – noncurrent	44	63
CECONY \| Preferred stock redemption
Regulatory assets
Regulatory assets – noncurrent	26	27
CECONY \| Recoverable energy costs
Regulatory assets
Regulatory assets – noncurrent	15	17
Regulatory assets – current	18	40
CECONY \| Workers’ compensation
Regulatory assets
Regulatory assets – noncurrent	11	8
CECONY \| Other
Regulatory assets
Regulatory assets – noncurrent	157	127
CECONY \| Deferred derivative losses
Regulatory assets
Regulatory assets – current	103	92
CECONY \| Property tax reconciliation
Regulatory liabilities
Regulatory liabilities – noncurrent	$ 303	$ 295

Capitalization - Additional Information (Detail)	12 Months Ended
Capitalization - Additional Information (Detail)	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares
Schedule of Capitalization [Line Items]
Common stock shares, outstanding \| shares	21,976,200	21,976,200
Percentage limitation for income available for dividends (not more than)	100.00%
Rolling average calculation of income available for dividends (years)	2 years
Tax-exempt debt issued, value	$ 450,000,000
Long-term debt, fair value	13,856,000,000	$ 13,913,000,000
Tax-exempt debt	1,086,000,000	1,130,000,000
Long-term debt	12,745,000,000	12,106,000,000
Deferred finance costs	$ 91,000,000	85,000,000
Debt instrument, covenant description	Con Edison's ratio of consolidated debt to consolidated capital to exceed 0.675 to 1
Covenant principal balance amount limit	$ 100,000,000
Level 2
Schedule of Capitalization [Line Items]
Long-term debt, fair value	13,220,000,000
Level 3
Schedule of Capitalization [Line Items]
Long-term debt, fair value	$ 636,000,000
Maximum
Schedule of Capitalization [Line Items]
Ratio of consolidated debt to consolidated capital for tax exempt financing	0.675
Transition Bonds, Issued in 2004
Schedule of Capitalization [Line Items]
Long-term debt	$ 15,000,000	18,000,000
CECONY
Schedule of Capitalization [Line Items]
Long-term debt, fair value	12,427,000,000	12,770,000,000
Tax-exempt debt	1,086,000,000	1,086,000,000
Long-term debt	11,437,000,000	11,138,000,000
Deferred finance costs	78,000,000	76,000,000
CECONY \| Level 2
Schedule of Capitalization [Line Items]
Long-term debt, fair value	11,791,000,000
CECONY \| Level 3
Schedule of Capitalization [Line Items]
Long-term debt, fair value	636,000,000
Tax-exempt debt	636,000,000
CECONY \| Minimum
Schedule of Capitalization [Line Items]
Covenant principal balance amount limit	150,000,000
CECONY \| Maximum
Schedule of Capitalization [Line Items]
Covenant principal balance amount limit	$ 100,000,000
Ratio of consolidated debt to consolidated capital for tax exempt financing	0.65
New Accounting Pronouncement, Early Adoption, Effect \| Other Assets
Schedule of Capitalization [Line Items]
Deferred finance costs	$ (91,000,000)	(85,000,000)
New Accounting Pronouncement, Early Adoption, Effect \| Other Assets \| CECONY
Schedule of Capitalization [Line Items]
Deferred finance costs	(78,000,000)	(76,000,000)
New Accounting Pronouncement, Early Adoption, Effect \| Long-term Debt
Schedule of Capitalization [Line Items]
Deferred finance costs	91,000,000	85,000,000
New Accounting Pronouncement, Early Adoption, Effect \| Long-term Debt \| CECONY
Schedule of Capitalization [Line Items]
Deferred finance costs	$ 78,000,000	$ 76,000,000

Capitalization - Schedule of Long-Term Debt Maturities (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
2016	$ 739
2017	16
2018	1,266
2019	552
2020	365
CECONY
Debt Instrument [Line Items]
2016	650
2017	0
2018	1,200
2019	475
2020	$ 350

Capitalization - Carrying Amounts and Fair Values of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Carrying Amount	$ 12,745	$ 12,106
Fair Value	13,856	13,913
CECONY
Debt Instrument [Line Items]
Carrying Amount	11,437	11,138
Fair Value	$ 12,427	$ 12,770

Short-Term Borrowing - Additional Information (Detail)	12 Months Ended
Short-Term Borrowing - Additional Information (Detail)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Oct. 31, 2011
Short-term Debt [Line Items]
Credit facility expiration date	Oct. 31, 2017
Commercial paper, outstanding	$ 1,529,000,000	$ 800,000,000
Weighted average interest rate	0.70%	0.40%
Loans outstanding under credit agreement	$ 0	$ 0
Letters of credit outstanding under the Credit Agreement	$ 15,000,000	11,000,000
Ratio of consolidated debt to consolidated total capital	0.52
Minimum percentage of liens on assets	5.00%
October 2016
Short-term Debt [Line Items]
Current amount available	$ 1,500,000,000
Maximum
Short-term Debt [Line Items]
Ratio of consolidated debt to consolidated total capital			0.65
Letters of Credit \| October 2016
Short-term Debt [Line Items]
Maximum credit available	2,250,000,000
Maximum borrowing capacity	1,200,000,000
Letters of Credit \| October 2017
Short-term Debt [Line Items]
Maximum credit available	2,100,000,000
CECONY
Short-term Debt [Line Items]
Commercial paper, outstanding	1,033,000,000	450,000,000
Letters of credit outstanding under the Credit Agreement	$ 11,000,000	$ 11,000,000

Pension Benefits - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Pension liability	$ 968,000,000
Investments value	243,000,000	$ 225,000,000
Other Nonqualified Supplemental Defined Benefit Pension
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	285,000,000	289,000,000
CECONY
Defined Benefit Plan Disclosure [Line Items]
Pension liability	899,000,000
Investments value	221,000,000	208,000,000
CECONY \| Other Nonqualified Supplemental Defined Benefit Pension
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	249,000,000	250,000,000
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Decrease to regulatory assets	967,000,000
Charge to OCI	10,000,000
Net loss estimated to be amortized	603,000,000
Prior service cost estimated to be amortized	4,000,000
Accumulated benefit obligation	12,909,000,000	13,454,000,000	$ 11,004,000,000
Defined benefit plan, bond amount (excess of)	50,000,000
Estimated future employer contributions	507,000,000
Increase in pension benefit obligation		800,000,000
Pension Benefits \| CECONY
Defined Benefit Plan Disclosure [Line Items]
Decrease to regulatory assets	911,000,000
Charge to OCI	1,000,000
Net loss estimated to be amortized	570,000,000
Prior service cost estimated to be amortized	2,000,000
Accumulated benefit obligation	12,055,000,000	$ 12,553,000,000	$ 10,268,000,000
Estimated future employer contributions	$ 469,000,000
Minimum \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, percent of bond original price	50.00%
Defined benefit plan, bond yield (percent)	1.00%
Maximum \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, percent of bond original price	200.00%
Defined benefit plan, bond yield (percent)	20.00%

Pension Benefits - Total Periodic Benefit Costs (Detail) - Pension Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Service cost – including administrative expenses	$ 297	$ 227	$ 267
Interest cost on projected benefit obligation	575	572	537
Expected return on plan assets	(886)	(832)	(750)
Recognition of net actuarial loss	775	618	832
Recognition of prior service costs	4	4	5
NET PERIODIC BENEFIT COST	765	589	891
Amortization of regulatory asset	1	2	2
TOTAL PERIODIC BENEFIT COST	766	591	893
Cost capitalized	(301)	(225)	(348)
Reconciliation to rate level	(74)	118	(84)
Cost charged to operating expenses	391	484	461
Increase in CECONY's pension obligation	45
CECONY
Defined Benefit Plan Disclosure [Line Items]
Service cost – including administrative expenses	279	211	249
Interest cost on projected benefit obligation	538	536	503
Expected return on plan assets	(840)	(789)	(713)
Recognition of net actuarial loss	734	586	788
Recognition of prior service costs	2	2	4
NET PERIODIC BENEFIT COST	713	546	831
Amortization of regulatory asset	1	2	2
TOTAL PERIODIC BENEFIT COST	714	548	833
Cost capitalized	(285)	(212)	(327)
Reconciliation to rate level	(74)	108	(87)
Cost charged to operating expenses	$ 355	$ 444	$ 419

Pension Benefits - Schedule of Funded Status (Detail) - Pension Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$ 15,081	$ 12,197	$ 13,406
Service cost – excluding administrative expenses	293	221	259
Interest cost on projected benefit obligation	575	572	537
Net actuarial (gain)/loss	(996)	2,641	(1,469)
Plan amendments	0	6	0
Benefits paid	(576)	(556)	(536)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	14,377	15,081	12,197
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	11,495	10,755	9,135
Actual return on plan assets	126	752	1,310
Employer contributions	750	578	879
Benefits paid	(576)	(556)	(536)
Administrative expenses	(36)	(34)	(33)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	11,759	11,495	10,755
FUNDED STATUS	(2,618)	(3,586)	(1,442)
Unrecognized net loss	3,909	4,888	2,759
Unrecognized prior service costs	16	20	17
Accumulated benefit obligation	12,909	13,454	11,004
CECONY
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	14,137	11,429	12,572
Service cost – excluding administrative expenses	274	206	241
Interest cost on projected benefit obligation	538	536	503
Net actuarial (gain)/loss	(931)	2,484	(1,388)
Plan amendments	0	0	0
Benefits paid	(536)	(518)	(499)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	13,482	14,137	11,429
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	10,897	10,197	8,668
Actual return on plan assets	118	715	1,241
Employer contributions	697	535	819
Benefits paid	(536)	(518)	(499)
Administrative expenses	(35)	(32)	(32)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	11,141	10,897	10,197
FUNDED STATUS	(2,341)	(3,240)	(1,232)
Unrecognized net loss	3,704	4,616	2,617
Unrecognized prior service costs	3	4	6
Accumulated benefit obligation	$ 12,055	$ 12,553	$ 10,268

Pension Benefits - Schedule of Assumptions (Detail) - Pension Benefits	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Discount rate, benefit obligations	4.25%	3.90%	4.80%
Discount rate, net periodic benefit cost	3.90%	4.80%	4.10%
Expected return on plan assets	7.80%	8.00%	8.00%
CECONY
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	4.25%	4.25%	4.35%
Rate of compensation increase	4.25%	4.35%	4.35%
O&R
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	4.00%	4.00%	4.25%
Rate of compensation increase	4.00%	4.25%	4.25%

Pension Benefits - Schedule of Expected Benefit Payments (Detail) - Pension Benefits $ in Millions	Dec. 31, 2015 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2016	$ 614
2017	636
2018	658
2019	680
2020	701
2021-2025	3,800
CECONY
Defined Benefit Plan Disclosure [Line Items]
2016	572
2017	593
2018	614
2019	635
2020	655
2021-2025	$ 3,548

Pension Benefits - Schedule of Plan Assets Allocations (Detail) - Pension Benefits	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Plan Assets, Total		100.00%	100.00%	100.00%
Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Equity Securities, target allocation minimum	55.00%
Equity Securities, target allocation maximum	65.00%
Debt Securities, target allocation minimum	27.00%
Debt Securities, target allocation maximum	33.00%
Real Estate, target allocation minimum	8.00%
Real Estate, target allocation maximum	12.00%
Plan Assets, Total	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets		57.00%	58.00%	60.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets		33.00%	32.00%	30.00%
Real Estate
Defined Benefit Plan Disclosure [Line Items]
Plan Assets		10.00%	10.00%	10.00%

Pension Benefits - Schedule of Fair Value of Plan Assets (Detail) - Pension Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Total investments	$ 12,548	$ 12,415
Funds for retiree health benefits	(325)	(358)
Investments (excluding funds for retiree health benefits)	12,223	12,057
Pending activities	(464)	(562)
Total fair value of plan net assets	11,759	11,495	$ 10,755	$ 9,135
U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	3,106	3,168
International Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	3,220	3,202
Private Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	170	114
Total fair value of plan net assets	170	114
U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	2,222	2,113
Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	1,356	1,351
Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	1	4
Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	170	208
Real Estate
Defined Benefit Plan Disclosure [Line Items]
Total investments	1,248	1,137
Total fair value of plan net assets	1,248	1,137
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total investments	529	665
Futures
Defined Benefit Plan Disclosure [Line Items]
Total investments	293	229
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Total investments	233	224
Total fair value of plan net assets	233	224
Level 1
Defined Benefit Plan Disclosure [Line Items]
Total investments	6,256	6,389
Funds for retiree health benefits	(162)	(184)
Investments (excluding funds for retiree health benefits)	6,094	6,205
Level 1 \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	3,106	3,168
Level 1 \| International Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	2,874	2,841
Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total investments	115	188
Level 1 \| Futures
Defined Benefit Plan Disclosure [Line Items]
Total investments	161	192
Level 2
Defined Benefit Plan Disclosure [Line Items]
Total investments	4,641	4,551
Funds for retiree health benefits	(120)	(131)
Investments (excluding funds for retiree health benefits)	4,521	4,420
Level 2 \| International Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	346	361
Level 2 \| U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	2,222	2,113
Level 2 \| Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	1,356	1,351
Level 2 \| Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	1	4
Level 2 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	170	208
Level 2 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total investments	414	477
Level 2 \| Futures
Defined Benefit Plan Disclosure [Line Items]
Total investments	132	37
Level 3
Defined Benefit Plan Disclosure [Line Items]
Total investments	1,651	1,475
Funds for retiree health benefits	(43)	(43)
Investments (excluding funds for retiree health benefits)	1,608	1,432
Level 3 \| Private Equity
Defined Benefit Plan Disclosure [Line Items]
Total investments	170	114
Total fair value of plan net assets		114	67
Level 3 \| Real Estate
Defined Benefit Plan Disclosure [Line Items]
Total investments	1,248	1,137
Total fair value of plan net assets		1,137	1,062
Level 3 \| Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Total investments	$ 233	224
Total fair value of plan net assets		$ 224	$ 206

Pension Benefits - Reconciliation of Fair Value Balances for Net Assets (Detail) - Pension Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	$ 11,495	$ 10,755
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	11,759	11,495
Real Estate
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	1,137
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	131
Assets Sold During the Year – Realized Gains/(Losses)	12
Purchases Sales and Settlements	(32)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	1,248	1,137
Private Equity
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	114
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	17
Purchases Sales and Settlements	39
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	170	114
Hedge Funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	224
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	3
Purchases Sales and Settlements	6
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	233	224
Investments
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	1,475
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	151
Assets Sold During the Year – Realized Gains/(Losses)	12
Purchases Sales and Settlements	13
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	1,651	1,475
Funds for Retiree Health Benefits
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	(43)
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	(43)	(43)
Investments (Excluding Funds for Retiree Health Benefits)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	1,432
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	151
Assets Sold During the Year – Realized Gains/(Losses)	12
Purchases Sales and Settlements	13
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	1,608	1,432
Level 3 \| Real Estate
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	1,137	1,062
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)		86
Assets Sold During the Year – Realized Gains/(Losses)		20
Purchases Sales and Settlements		(31)
Transfer In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR		1,137
Level 3 \| Private Equity
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	114	67
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)		12
Purchases Sales and Settlements		35
Transfer In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR		114
Level 3 \| Hedge Funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	224	206
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)		11
Purchases Sales and Settlements		7
Transfer In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR		224
Level 3 \| Investments
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	1,475	1,335
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)		109
Assets Sold During the Year – Realized Gains/(Losses)		20
Purchases Sales and Settlements		11
Transfer In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR		1,475
Level 3 \| Funds for Retiree Health Benefits
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	(43)	(42)
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)		(1)
Purchases Sales and Settlements		0
Transfer In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR		(43)
Level 3 \| Investments (Excluding Funds for Retiree Health Benefits)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	1,432	1,293
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)		108
Assets Sold During the Year – Realized Gains/(Losses)		20
Purchases Sales and Settlements		11
Transfer In/(Out) of Level 3	$ 0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR		$ 1,432

Other Postretirement Benefits - Additional Information (Detail) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Decrease in liability for other postretirement benefits	$ 34
Increase (decrease) to regulatory assets	30
Charge to OCI	(1)
Net losses unrecognized to be amortized	12
Prior service cost estimated to be amortized	$ 20
Health care cost trend rate for net periodic benefit cost, current	5.25%
Health care cost trend rate for net periodic benefit cost	4.50%
Year for final trend rate for net periodic benefit cost	2018
Health care cost trend rate for benefit obligations, current	6.00%
Health care cost trend rate for benefit obligations	4.50%
Year for final trend rate for benefit obligations	2024
Expected contributions	$ 5
Maximum
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in postretirement benefit obligations		$ 10
CECONY
Defined Benefit Plan Disclosure [Line Items]
Decrease in liability for other postretirement benefits	30
Increase (decrease) to regulatory assets	27
Net losses unrecognized to be amortized	10
Prior service cost estimated to be amortized	14
Expected contributions	$ 5

Other Postretirement Benefits - Net Periodic Postretirement Benefit Costs (Detail) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 20	$ 19	$ 23
Interest cost on accumulated other postretirement benefit obligation	51	60	54
Expected return on plan assets	(78)	(77)	(77)
Recognition of net actuarial loss	31	57	65
Recognition of prior service cost	(20)	(19)	(27)
NET PERIODIC BENEFIT COST	4	40	38
Cost capitalized	(2)	(15)	(15)
Reconciliation to rate level	14	10	58
Cost charged to operating expenses	16	35	81
CECONY
Defined Benefit Plan Disclosure [Line Items]
Service cost	15	15	18
Interest cost on accumulated other postretirement benefit obligation	43	52	46
Expected return on plan assets	(68)	(68)	(68)
Recognition of net actuarial loss	28	51	57
Recognition of prior service cost	(14)	(15)	(23)
NET PERIODIC BENEFIT COST	4	35	30
Cost capitalized	(2)	(14)	(12)
Reconciliation to rate level	6	2	50
Cost charged to operating expenses	$ 8	$ 23	$ 68

Other Postretirement Benefits - Schedule of Funded Status (Detail) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CHANGE IN BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$ 1,411	$ 1,395	$ 1,454
Service cost	20	19	23
Interest cost on accumulated other postretirement benefit obligation	51	60	54
Amendments	0	(12)	0
Net actuarial loss/(gain)	(103)	47	(42)
Benefits paid and administrative expenses	(127)	(134)	(136)
Participant contributions	35	36	38
Medicare prescription subsidy	0	0	4
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	1,287	1,411	1,395
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	1,084	1,113	1,047
Actual return on plan assets	(6)	59	153
Employer contributions	6	7	9
EGWP payments	28	12	8
Participant contributions	35	36	38
Benefits paid	(153)	(143)	(142)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	994	1,084	1,113
FUNDED STATUS	(293)	(327)	(282)
Unrecognized net loss	28	78	70
Unrecognized prior service costs	(51)	(71)	(78)
CECONY
CHANGE IN BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	1,203	1,198	1,238
Service cost	15	15	18
Interest cost on accumulated other postretirement benefit obligation	43	52	46
Amendments	0	0	0
Net actuarial loss/(gain)	(85)	28	(20)
Benefits paid and administrative expenses	(117)	(125)	(126)
Participant contributions	34	35	38
Medicare prescription subsidy	0	0	4
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	1,093	1,203	1,198
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	950	977	922
Actual return on plan assets	(4)	54	134
Employer contributions	6	7	9
EGWP payments	26	11	7
Participant contributions	34	35	38
Benefits paid	(142)	(134)	(133)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	870	950	977
FUNDED STATUS	(223)	(253)	(221)
Unrecognized net loss	4	45	54
Unrecognized prior service costs	$ (32)	$ (46)	$ (61)

Other Postretirement Benefits - Schedule of Actuarial Assumptions (Detail) - Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	7.75%	7.75%	7.75%
CECONY
Defined Benefit Plan Disclosure [Line Items]
Discount rate, benefit obligations	4.05%	3.75%	4.50%
Discount rate, net periodic benefit cost	3.75%	4.50%	3.75%
O&R
Defined Benefit Plan Disclosure [Line Items]
Discount rate, benefit obligations	4.20%	3.85%	4.75%
Discount rate, net periodic benefit cost	3.85%	4.75%	4.05%

Other Postretirement Benefits - Schedule of Change of Assumed Health Care Cost Trend Rate (Detail) - Scenario, Forecast - Other Postretirement Benefits $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on accumulated other postretirement benefit obligation, Increase	$ (18)
Effect on service cost and interest cost components for 2015, Increase	(1)
Effect on accumulated other postretirement benefit obligation, Decrease	41
Effect on service cost and interest cost components for 2015, Decrease	1
CECONY
Defined Benefit Plan Disclosure [Line Items]
Effect on accumulated other postretirement benefit obligation, Increase	(37)
Effect on service cost and interest cost components for 2015, Increase	(3)
Effect on accumulated other postretirement benefit obligation, Decrease	56
Effect on service cost and interest cost components for 2015, Decrease	$ 2

Other Postretirement Benefits - Schedule of Expected Benefit Payments (Detail) - Other Postretirement Benefits $ in Millions	Dec. 31, 2015 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2016 - Benefit Payments	$ 95
2017 - Benefit Payments	93
2018 - Benefit Payments	91
2019 - Benefit Payments	88
2020 - Benefit Payments	85
2020-2025 - Benefit Payments	403
CECONY
Defined Benefit Plan Disclosure [Line Items]
2016 - Benefit Payments	85
2017 - Benefit Payments	83
2018 - Benefit Payments	81
2019 - Benefit Payments	78
2020 - Benefit Payments	75
2020-2025 - Benefit Payments	$ 348

Other Postretirement Benefits - Schedule of Plan Assets Allocations (Detail) - CECONY - Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Plan Assets		100.00%	100.00%	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets		59.00%	59.00%	61.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets		41.00%	41.00%	39.00%
Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range, Total	100.00%
Scenario, Forecast \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation, Minimum	57.00%
Target Allocation, Maximum	73.00%
Scenario, Forecast \| Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation, Minimum	26.00%
Target Allocation, Maximum	44.00%

Other Postretirement Benefits - Schedule of Fair Values of Plan Assets (Detail) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Total investments	$ 660	$ 725
Funds for retiree health benefits	325	358
Investments (including funds for retiree health benefits)	985	1,083
Pending activities	9	1
Total fair value of plan net assets	994	1,084	$ 1,113	$ 1,047
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total investments	393	428
Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	260	286
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total investments	7	11
Level 1
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	162	184
Investments (including funds for retiree health benefits)	162	184
Level 2
Defined Benefit Plan Disclosure [Line Items]
Total investments	660	725
Funds for retiree health benefits	120	131
Investments (including funds for retiree health benefits)	780	856
Level 2 \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total investments	393	428
Level 2 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total investments	260	286
Level 2 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total investments	7	11
Level 3
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	43	43
Investments (including funds for retiree health benefits)	$ 43	$ 43

Other Postretirement Benefits - Reconciliation of Fair Value Balances for Net Assets (Detail) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 1,084	$ 1,113
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	994	1,084
Level 3
Defined Benefit Plan Disclosure [Line Items]
Assets Sold During the Year – Realized Gains/(Losses)	0	0
Purchases Sales and Settlements	0
Transfers In/(Out) of Level 3	0	0
Level 3 \| Funds for Retiree Health Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	43	42
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	0	1
Assets Sold During the Year – Realized Gains/(Losses)	0	0
Purchases Sales and Settlements		0
Transfers In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	43	43
Level 3 \| Investments (including funds for retiree health benefits) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	43	42
Assets Still Held at Reporting Date – Unrealized Gains/ (Losses)	0	1
Assets Sold During the Year – Realized Gains/(Losses)	0	0
Purchases Sales and Settlements		0
Transfers In/(Out) of Level 3	0	0
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$ 43	$ 43

Environmental Matters - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Site Contingency [Line Items]
Remediation cost estimate	$ 37	$ 29
Other Superfund Sites
Site Contingency [Line Items]
Remediation cost estimate	51
Other Superfund Sites \| Manufactured gas plant sites \| Maximum
Site Contingency [Line Items]
Estimated aggregate undiscounted potential liability related environmental contaminants (up to)	2,800
CECONY
Site Contingency [Line Items]
Remediation cost estimate	$ 34	$ 20
CECONY \| Asbestos Proceedings
Site Contingency [Line Items]
Estimated undiscounted asbestos liability (years)	15 years
CECONY \| Other Superfund Sites
Site Contingency [Line Items]
Remediation cost estimate	$ 36
CECONY \| Other Superfund Sites \| Manufactured gas plant sites \| Maximum
Site Contingency [Line Items]
Estimated aggregate undiscounted potential liability related environmental contaminants (up to)	$ 2,700

Environmental Matters - Accrued Liabilities and Regulatory Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities:
Accrued Liabilities	$ 765	$ 764
Regulatory assets	8,228	9,280
Manufactured gas plant sites
Accrued Liabilities:
Accrued Liabilities	679	684
Other Superfund Sites
Accrued Liabilities:
Accrued Liabilities	86	80
Other Superfund Sites
Accrued Liabilities:
Accrued Liabilities	765	764
Regulatory assets	904	925
CECONY
Accrued Liabilities:
Accrued Liabilities	665	666
Regulatory assets	7,603	8,589
CECONY \| Manufactured gas plant sites
Accrued Liabilities:
Accrued Liabilities	579	587
CECONY \| Other Superfund Sites
Accrued Liabilities:
Accrued Liabilities	86	79
CECONY \| Other Superfund Sites
Accrued Liabilities:
Accrued Liabilities	665	666
Regulatory assets	$ 800	$ 820

Environmental Matters - Environmental Remediation Costs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Environmental Exit Cost [Line Items]
Remediation costs incurred	$ 37	$ 29
Insurance recoveries received	0	7
CECONY
Environmental Exit Cost [Line Items]
Remediation costs incurred	34	20
Insurance recoveries received	$ 0	$ 7

Environmental Matters - Accrued Liability for Asbestos Suits and Workers' Compensation Proceedings (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Site Contingency [Line Items]
Regulatory assets	$ 8,228	$ 9,280
Asbestos Suits
Site Contingency [Line Items]
Accrued liability	8	8
Regulatory assets	8	8
Workers Compensation Insurance
Site Contingency [Line Items]
Accrued liability	86	83
Regulatory assets	11	8
CECONY
Site Contingency [Line Items]
Regulatory assets	7,603	8,589
CECONY \| Asbestos Suits
Site Contingency [Line Items]
Accrued liability	7	7
Regulatory assets	7	7
CECONY \| Workers Compensation Insurance
Site Contingency [Line Items]
Accrued liability	81	78
Regulatory assets	$ 11	$ 8

Other Material Contingencies - Additional Information (Detail)		1 Months Ended	12 Months Ended
	Mar. 12, 2014 People building	Jul. 31, 2007 Person	Dec. 31, 2015 USD ($) Lawsuits	Dec. 31, 2014 USD ($)
Guarantor Obligations [Line Items]
Number of people who died in stream rupture incident \| Person		1
Number of suits pending against the company \| Lawsuits			90
Estimated accrued liability for suits			$ 50,000,000
Insurance receivable for suits			50,000,000
Number of buildings destroyed by fire \| building	2
Number of people who died in explosion or fire incident \| People	8
Number of people injured in explosion and fire incident (more than) \| People	50
Guarantee obligations maximum exposure			$ 2,856,000,000	$ 2,547,000,000
Ownership interest, percentage			45.70%
Estimated project cost percentage			175.00%
Manhattan Explosion and Fire
Guarantor Obligations [Line Items]
Number of suits pending against the company \| Lawsuits			70
Other
Guarantor Obligations [Line Items]
Guarantee obligations maximum exposure			$ 75,000,000
Indemnity agreements amount			70,000,000
Electric provider obligation to Public Utility Commission of Texas			$ 5,000,000

Other Material Contingencies - Total Guarantees (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Total guarantees, by type and term	$ 2,856,000,000	$ 2,547,000,000
NY Transco
Guarantor Obligations [Line Items]
Total guarantees, by type and term	1,358,000,000
Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	924,000,000
Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	499,000,000
Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	75,000,000
0 – 3 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	2,129,000,000
0 – 3 years \| NY Transco
Guarantor Obligations [Line Items]
Total guarantees, by type and term	791,000,000
0 – 3 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	792,000,000
0 – 3 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	471,000,000
0 – 3 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	75,000,000
4 – 10 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	603,000,000
4 – 10 years \| NY Transco
Guarantor Obligations [Line Items]
Total guarantees, by type and term	567,000,000
4 – 10 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	35,000,000
4 – 10 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	1,000,000
Greater than 10 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	124,000,000
Greater than 10 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	97,000,000
Greater than 10 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	$ 27,000,000

Electricity Purchase Agreements - Summary of Significant Terms of Electricity Purchase Agreements (Detail) - CECONY	12 Months Ended
	Dec. 31, 2015 MW
Brooklyn Navy Yard
Long-term Contract for Purchase of Electric Power [Line Items]
Plant Output (MW)	322
Contracted Output (MW)	299
Contract Term (Years)	40 years
Linden Cogeneration
Long-term Contract for Purchase of Electric Power [Line Items]
Plant Output (MW)	1,035
Contracted Output (MW)	609
Contract Term (Years)	25 years
Indian Point
Long-term Contract for Purchase of Electric Power [Line Items]
Plant Output (MW)	2,311
Contracted Output (MW)	500
Contract Term (Years)	16 years
Astoria Energy
Long-term Contract for Purchase of Electric Power [Line Items]
Plant Output (MW)	640
Contracted Output (MW)	500
Contract Term (Years)	10 years

Electricity Purchase Agreements - Summary of Estimated Capacity and Other Fixed Payments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
2016
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	$ 222
2017
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	207
2018
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	181
2019
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	98
2020
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	53
All Years Thereafter
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	762
CECONY
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	865	$ 1,312	$ 1,282
CECONY \| 2016
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	218
CECONY \| 2017
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	205
CECONY \| 2018
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	181
CECONY \| 2019
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	98
CECONY \| 2020
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	53
CECONY \| All Years Thereafter
Long-term Contract for Purchase of Electric Power [Line Items]
Fixed payment under the contracts	$ 762

Electricity Purchase Agreements - Summary of Capacity, Energy and Other Fixed Payments (Detail) - CECONY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	$ 865	$ 1,312	$ 1,282
Linden Cogeneration
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	323	381	346
Indian Point
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	226	247	220
Astoria Energy
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	178	230	183
Brooklyn Navy Yard
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	113	133	118
Indeck Corinth
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	25	80	79
Selkirk
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	0	144	215
Independence
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	$ 0	$ 97	$ 121

Leases - Additional Information (Detail) $ in Millions	12 Months Ended
Leases - Additional Information (Detail) $ in Millions	Dec. 31, 2015 USD ($) transaction	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Operating Leased Assets [Line Items]
Accumulated amortization	$ 3	$ 2
Number of LILO transactions \| transaction	2
Estimated charge after-tax			$ 150
Gain from LILO transaction termination			55
Decrease in net income		1	$ 95
CECONY
Operating Leased Assets [Line Items]
Accumulated amortization	$ 2	$ 1

Leases - Future Minimum Lease Commitments (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Capital Leased Assets [Line Items]
2016	$ 1
2017	1
2018	1
2019	0
2020	0
All years thereafter	0
Total	3
Less: amount representing interest	1
Present value of net minimum lease payment	2
CECONY
Capital Leased Assets [Line Items]
2016	1
2017	1
2018	1
2019	0
2020	0
All years thereafter	0
Total	3
Less: amount representing interest	1
Present value of net minimum lease payment	$ 2

Leases - Future Minimum Rental Payments for Operating Leases (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Operating Leased Assets [Line Items]
2016	$ 18
2017	18
2018	18
2019	16
2020	15
All years thereafter	123
Total	208
CECONY
Operating Leased Assets [Line Items]
2016	12
2017	12
2018	12
2019	10
2020	9
All years thereafter	42
Total	$ 97

Goodwill - Additional Information (Detail) $ in Millions	12 Months Ended
Goodwill - Additional Information (Detail) $ in Millions	Dec. 31, 2015 USD ($) business_acquisition	Dec. 31, 2014 USD ($) business_acquisition
Goodwill [Line Items]
Goodwill	$ 429	$ 429
Number of businesses acquired included in goodwill impairment test \| business_acquisition	2	2,000,000
O&R
Goodwill [Line Items]
Goodwill	$ 406	$ 406
CECONY
Goodwill [Line Items]
Goodwill	245	245
O&R
Goodwill [Line Items]
Goodwill	161	161
Energy Services Acquired
Goodwill [Line Items]
Goodwill	$ 23	$ 23

Income Tax - Additional Information (Detail) - USD ($)		1 Months Ended			12 Months Ended
Income Tax - Additional Information (Detail) - USD ($)	Dec. 31, 2013	Feb. 29, 2016	Jan. 31, 2016	Jan. 31, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011	Dec. 31, 2010
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, accelerated bonus depreciation									$ 6,000,000
Valuation allowance									258,000,000
Deferred tax asset, valuation allowance									$ (15,000,000)	$ (11,000,000)
Deferred tax assets, charitable contribution carryforwards												$ 9,000,000	$ 1,000,000
Corporate franchise tax rate									7.10%
Decrease in accumulated deferred tax liabilities										74,000,000
Decrease in regulatory asset										11,000,000
Increase in regulatory liability										62,000,000
Bonus depreciation percentage	50.00%								50.00%
Income tax refund requested				$ 224,000,000
Effective income tax rate reconciliation, uncertainty of taxes									$ 25,000,000
Effective income tax rate reconciliation, uncertainty net of federal taxes									16,000,000
Interest charges related to uncertain tax positions											$ 121,000,000
Interest charges related to uncertain tax position, LILO transaction											131,000,000
Reduced interest expenses											$ 10,000,000
Amount of interest and penalties in their consolidated balance sheets									0	0
Unrecognized tax benefits amount									34,000,000
Unrecognized tax benefits, net of federal taxes									22,000,000
CECONY
Operating Loss Carryforwards [Line Items]
Deferred tax asset, valuation allowance									0	0
Decrease in accumulated deferred tax liabilities										69,000,000
Decrease in regulatory asset										10,000,000
Increase in regulatory liability										59,000,000
Income tax refund requested				$ 128,000,000
Effective income tax rate reconciliation, uncertainty of taxes									2,000,000
Effective income tax rate reconciliation, uncertainty net of federal taxes									1,000,000
Unrecognized tax benefits amount									2,000,000
Unrecognized tax benefits, net of federal taxes									1,000,000
New York City
Operating Loss Carryforwards [Line Items]
Deferred tax asset, valuation allowance									(11,000,000)
New Accounting Pronouncement, Early Adoption, Effect
Operating Loss Carryforwards [Line Items]
Deferred tax assets, current										(128,000,000)
Deferred tax assets, noncurrent										128,000,000
New Accounting Pronouncement, Early Adoption, Effect \| CECONY
Operating Loss Carryforwards [Line Items]
Deferred tax assets, current										(94,000,000)
Deferred tax assets, noncurrent										$ 94,000,000
Subsequent Event
Operating Loss Carryforwards [Line Items]
Corporate franchise tax rate			6.50%
Income tax refund requested			$ 160,000,000
Income tax refund		$ 160,000,000
Subsequent Event \| CECONY
Operating Loss Carryforwards [Line Items]
Income tax refund		$ 143,000,000
Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Bonus depreciation percentage					30.00%	40.00%	50.00%	50.00%
Charitable Contribution
Operating Loss Carryforwards [Line Items]
Deferred tax asset, valuation allowance									$ (4,000,000)

Income Tax - Schedule of Components of Income Tax (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax [Line Items]
State - Current	$ 38	$ 59	$ 151
State - Deferred	93	61	(70)
Federal - Current	(86)	(9)	285
Federal - Deferred	569	463	115
Amortization of investment tax credits	(9)	(6)	(5)
Total income tax expense	605	568	476
CECONY
Income Tax [Line Items]
State - Current	48	66	111
State - Deferred	82	65	(14)
Federal - Current	77	158	187
Federal - Deferred	372	271	241
Amortization of investment tax credits	(5)	(5)	(5)
Total income tax expense	$ 574	$ 555	$ 520

Income Tax - Schedule of Differences on Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Contingency [Line Items]
Property basis differences	$ 8,614	$ 7,510
Unrecognized pension and other postretirement costs	1,562	1,968
Future income tax	947	910
Environmental remediation costs	365	376
Deferred storm costs	75	129
Other regulatory assets	367	347
Equity investments	295	168
Total deferred tax liabilities	12,225	11,408
Accrued pension and other postretirement costs	982	1,306
Regulatory liabilities	836	615
Superfund and other environmental costs	308	306
Asset retirement obligations	97	77
Loss carryforwards	29	21
Tax credits carryforward	258	0
Valuation allowance	(15)	(11)
Other	362	272
Total deferred tax assets	2,857	2,586
Net deferred tax liabilities	9,368	8,822
Unamortized investment tax credits	169	126
Net deferred tax liabilities and unamortized investment tax credits	9,537	8,948
CECONY
Income Tax Contingency [Line Items]
Property basis differences	7,922	6,938
Unrecognized pension and other postretirement costs	1,490	1,872
Future income tax	899	863
Environmental remediation costs	322	333
Deferred storm costs	45	91
Other regulatory assets	308	300
Equity investments	0	0
Total deferred tax liabilities	10,986	10,397
Accrued pension and other postretirement costs	857	1,155
Regulatory liabilities	752	574
Superfund and other environmental costs	268	264
Asset retirement obligations	94	75
Loss carryforwards	0
Tax credits carryforward	1	0
Valuation allowance	0	0
Other	292	203
Total deferred tax assets	2,264	2,271
Net deferred tax liabilities	8,722	8,126
Unamortized investment tax credits	33	37
Net deferred tax liabilities and unamortized investment tax credits	$ 8,755	$ 8,163

Income Tax - Schedule of Income Tax Reconciliation (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Contingency [Line Items]
Federal	35.00%	35.00%	35.00%
State income tax	5.00%	5.00%	4.00%
Cost of removal	(5.00%)	(5.00%)	(5.00%)
Manufacturing deduction	(0.00%)	(0.00%)	(1.00%)
Other	(1.00%)	(1.00%)	(2.00%)
Effective tax rate	34.00%	34.00%	31.00%
CECONY
Income Tax Contingency [Line Items]
Federal	35.00%	35.00%	35.00%
State income tax	5.00%	5.00%	5.00%
Cost of removal	(5.00%)	(5.00%)	(5.00%)
Manufacturing deduction	(0.00%)	(0.00%)	(0.00%)
Other	0.00%	(1.00%)	(1.00%)
Effective tax rate	35.00%	34.00%	34.00%

Income Tax - Summary of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1,	$ 34	$ 9	$ 86
Additions based on tax positions related to the current year	0	0	5
Additions based on tax positions of prior years	1	27	253
Reductions for tax positions of prior years	0	(2)	(86)
Reductions from expiration of statute of limitations	(1)	0	0
Settlements	0	0	(249)
Balance at December 31,	34	34	9
CECONY
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1,	2	0	74
Additions based on tax positions related to the current year	0	0	0
Additions based on tax positions of prior years	0	2	0
Reductions for tax positions of prior years	0	0	(74)
Reductions from expiration of statute of limitations	0	0	0
Settlements	0	0	0
Balance at December 31,	$ 2	$ 2	$ 0

Stock-Based Compensation - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option awards, LTIP (up to)	5,000,000
Stock options vesting period (years)	3 years
Income tax benefit	$ 14,000,000	$ 12,000,000	$ 11,000,000
Number of units issued	30,724
LTIP Weighted Average Price (dollars per share)	$ 61.31
Maximum employer contribution match (up to)	$ 1
Amount employee contribution for employer match	9
Maximum employee investment per year (up to)	$ 25,000
Maximum percentage allowed to invest (not more than)	20.00%
Shares purchased on the open market	761,784	708,276	864,281
Weighted average share price per share, on shares purchased on open market	$ 62.75	$ 56.23	$ 57.24
Time Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense recognized in future periods	$ 2,000,000
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit	$ 12,000,000	$ 10,000,000	$ 10,000,000
CECONY \| Time Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total expense recognized in future periods	$ 2,000,000
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit	$ 1,000,000	$ 1,000,000	$ 10,000,000
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options vesting period (years)	3 years
TSR Portion
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustment percentage used for Performance awards	50.00%
Factor used for adjustment of Performance awards, low end (percent)	0.00%
Factor used for adjustment of Performance awards, high end (percent)	200.00%
Non-TSR Portion
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustment percentage used for Performance awards	50.00%
Factor used for adjustment of Performance awards, low end (percent)	0.00%
Factor used for adjustment of Performance awards, high end (percent)	200.00%
Non-TSR Portion \| Management Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Factor used for adjustment of Performance awards, low end (percent)	0.00%
Factor used for adjustment of Performance awards, high end (percent)	120.00%
Performance-Based Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock received upon vesting	one share
Common stock received upon vesting (shares)	1
Compensation expense to be recognized	$ 29,000,000
Weighted average period (years)	1 year
Performance-Based Restricted Stock \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense to be recognized	$ 23,000,000
Weighted average period (years)	1 year
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option expiration period (years)	10 years

Stock-Based Compensation - Stock-Based Compensation Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 34	$ 29	$ 27
Income tax benefit	14	12	11
Performance-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	27	22	20
Time-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	1	2	2
Non-employee director deferred stock compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	2	2
Stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	4	3	3
CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	29	26	25
Income tax benefit	12	10	10
CECONY \| Performance-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	23	19	18
CECONY \| Time-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	1	2	2
CECONY \| Non-employee director deferred stock compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	2	2
CECONY \| Stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 3	$ 3	$ 3

Stock-Based Compensation - Summary of Status of Stock Options (Detail)	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding Shares, Beginning Balance \| shares	229,850
Exercised, Shares \| shares	150,225
Forfeited, Shares \| shares	500
Outstanding Shares, Ending Balance \| shares	79,125
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Weighted Average Exercise Price Outstanding, Beginning Balance (dollars per share) \| $ / shares	$ 42.99
Weighted Average Exercise Price, Exercised (dollars per share) \| $ / shares	42.71
Weighted Average Exercise Price, Forfeited (dollars per share) \| $ / shares	43.50
Weighted Average Exercise Price Outstanding, Ending Balance (dollars per share) \| $ / shares	$ 43.50
Weighted average remaining contractual life (years)	1 year
CECONY
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding Shares, Beginning Balance \| shares	191,350
Exercised, Shares \| shares	125,575
Forfeited, Shares \| shares	0
Outstanding Shares, Ending Balance \| shares	65,775
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Weighted Average Exercise Price Outstanding, Beginning Balance (dollars per share) \| $ / shares	$ 43.00
Weighted Average Exercise Price, Exercised (dollars per share) \| $ / shares	42.74
Weighted Average Exercise Price, Forfeited (dollars per share) \| $ / shares	0.00
Weighted Average Exercise Price Outstanding, Ending Balance (dollars per share) \| $ / shares	$ 43.50
Weighted average remaining contractual life (years)	1 year

Stock-Based Compensation - Summary of Stock Options (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Aggregate intrinsic value
Options outstanding	$ 2	$ 5
Options exercised	3	4
Cash received by Con Edison for payment of exercise price	6	11
CECONY
Aggregate intrinsic value
Options outstanding	1	4
Options exercised	3	3
Cash received by Con Edison for payment of exercise price	$ 5	$ 8

Stock-Based Compensation - Assumptions Used to Calculate Fair Value (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Risk-free interest rate, minimum (percent)	0.64%	0.23%	0.13%
Risk-free interest rate, maximum (percent)	3.28%	3.07%	5.17%
Expected term (years)	3 years	3 years	3 years
Expected share price volatility (percent)	15.82%	13.14%	13.52%
Expected volatility calculation period (years)	3 years

Stock-Based Compensation - Summary of Changes in Status of Performance RSUs' (Detail) - Performance-Based Restricted Stock	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested Units, Beginning Balance \| shares	1,100,607
Granted, Units \| shares	363,900
Vested, Units \| shares	(327,536)
Forfeited, Units \| shares	(58,632)
Non-vested Units, Ending Balance \| shares	1,078,339
CECONY
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested Units, Beginning Balance \| shares	880,523
Granted, Units \| shares	288,669
Vested, Units \| shares	(266,683)
Forfeited, Units \| shares	(49,252)
Non-vested Units, Ending Balance \| shares	853,257
TSR Portion
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value Non-vested, Beginning Balance (dollars per share)	$ 42.33
Weighted Average Grant Date Fair Value, Granted (dollars per share)	57.67
Weighted Average Grant Date Fair Value, Vested (dollars per share)	49.45
Weighted Average Grant Date Fair Value, Forfeited (dollars per share)	43.84
Weighted Average Grant Date Fair Value Non-vested, Ending Balance (dollars per share)	$ 45.26
Adjustment percentage used for Performance awards	50.00%
TSR Portion \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value Non-vested, Beginning Balance (dollars per share)	$ 42.58
Weighted Average Grant Date Fair Value, Granted (dollars per share)	57.22
Weighted Average Grant Date Fair Value, Vested (dollars per share)	49.34
Weighted Average Grant Date Fair Value, Forfeited (dollars per share)	43.54
Weighted Average Grant Date Fair Value Non-vested, Ending Balance (dollars per share)	$ 45.37
Adjustment percentage used for Performance awards	50.00%
Non-TSR Portion
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value Non-vested, Beginning Balance (dollars per share)	$ 56.61
Weighted Average Grant Date Fair Value, Granted (dollars per share)	63.22
Weighted Average Grant Date Fair Value, Vested (dollars per share)	58.84
Weighted Average Grant Date Fair Value, Forfeited (dollars per share)	58.25
Weighted Average Grant Date Fair Value Non-vested, Ending Balance (dollars per share)	$ 58.08
Adjustment percentage used for Performance awards	50.00%
Non-TSR Portion \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value Non-vested, Beginning Balance (dollars per share)	$ 56.70
Weighted Average Grant Date Fair Value, Granted (dollars per share)	63.12
Weighted Average Grant Date Fair Value, Vested (dollars per share)	58.83
Weighted Average Grant Date Fair Value, Forfeited (dollars per share)	58.14
Weighted Average Grant Date Fair Value Non-vested, Ending Balance (dollars per share)	$ 58.12

Stock-Based Compensation - Summary of Changes in Status of Time-Based Awards (Detail) - Time Based Awards	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested Units, Beginning Balance \| shares	65,423
Granted, Units \| shares	23,000
Vested, Units \| shares	(20,773)
Forfeited, Units \| shares	(2,670)
Non-vested Units, Ending Balance \| shares	64,980
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value Non-vested, Beginning Balance (dollars per share) \| $ / shares	$ 57.65
Weighted Average Grant Date Fair Value, Granted (dollars per share) \| $ / shares	61.00
Weighted Average Grant Date Fair Value, Vested (dollars per share) \| $ / shares	58.42
Weighted Average Grant Date Fair Value, Forfeited (dollars per share) \| $ / shares	58.35
Weighted Average Grant Date Fair Value Non-vested, Ending Balance (dollars per share) \| $ / shares	$ 58.56
CECONY
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested Units, Beginning Balance \| shares	62,173
Granted, Units \| shares	21,800
Vested, Units \| shares	(19,773)
Forfeited, Units \| shares	(2,570)
Non-vested Units, Ending Balance \| shares	61,630
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value Non-vested, Beginning Balance (dollars per share) \| $ / shares	$ 57.64
Weighted Average Grant Date Fair Value, Granted (dollars per share) \| $ / shares	61.00
Weighted Average Grant Date Fair Value, Vested (dollars per share) \| $ / shares	58.42
Weighted Average Grant Date Fair Value, Forfeited (dollars per share) \| $ / shares	58.39
Weighted Average Grant Date Fair Value Non-vested, Ending Balance (dollars per share) \| $ / shares	$ 58.55

Financial Information by Business Segment - Financial Data for Business Segments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating revenues	$ 12,554	$ 12,919	$ 12,354
Depreciation and amortization	1,130	1,071	1,024
Operating income	2,427	2,209	2,244
Interest charges	653	591	719
Income taxes on operating income	644	589	504
Total assets	45,642	44,071	40,451
Construction expenditures	3,418	2,721	2,648
Income taxes on non-operating income	40	21	28
CECONY
Segment Reporting Information [Line Items]
Operating revenues	10,328	10,786	10,430
Depreciation and amortization	1,040	991	946
Operating income	2,247	2,139	2,060
Interest charges	584	537	521
Income taxes on operating income	588	562	531
Total assets	40,230	39,443	36,095
Construction expenditures	2,435	2,132	2,135
Income taxes on non-operating income	14	7	11
CECONY \| Electric
Segment Reporting Information [Line Items]
Depreciation and amortization	820	781	749
Operating income	1,798	1,712	1,595
Interest charges	447	412	402
Income taxes on operating income	447	425	380
Total assets	30,603	30,295	27,547
Construction expenditures	1,658	1,500	1,471
CECONY \| Gas
Segment Reporting Information [Line Items]
Depreciation and amortization	142	132	130
Operating income	356	314	362
Interest charges	96	89	83
Income taxes on operating income	100	88	112
Total assets	6,974	6,478	5,977
Construction expenditures	671	549	536
CECONY \| Steam
Segment Reporting Information [Line Items]
Depreciation and amortization	78	78	67
Operating income	93	113	103
Interest charges	41	36	36
Income taxes on operating income	41	49	39
Total assets	2,653	2,670	2,571
Construction expenditures	106	83	128
O&R
Segment Reporting Information [Line Items]
Depreciation and amortization	68	61	56
Operating income	121	128	120
Interest charges	35	35	37
Income taxes on operating income	33	35	20
Total assets	2,719	2,810	2,524
Construction expenditures	160	142	135
O&R \| Electric
Segment Reporting Information [Line Items]
Depreciation and amortization	50	46	41
Operating income	103	103	87
Interest charges	23	24	25
Income taxes on operating income	31	29	13
Total assets	2,140	2,023	1,882
Construction expenditures	114	105	98
O&R \| Gas
Segment Reporting Information [Line Items]
Depreciation and amortization	18	15	15
Operating income	18	25	33
Interest charges	12	10	11
Income taxes on operating income	2	6	7
Total assets	579	786	640
Construction expenditures	46	37	37
O&R \| Other
Segment Reporting Information [Line Items]
Interest charges	0	1	1
Total assets	0	1	2
Competitive energy businesses
Segment Reporting Information [Line Items]
Depreciation and amortization	22	19	23
Operating income	58	(60)	63
Interest charges	11	(8)	135
Income taxes on operating income	22	(8)	(41)
Total assets	1,680	1,013	1,305
Construction expenditures	823	447	378
Other
Segment Reporting Information [Line Items]
Depreciation and amortization		0	(1)
Operating income	1	2	1
Interest charges	23	27	26
Income taxes on operating income	1	0	(6)
Total assets	1,013	805	527
Operating revenues
Segment Reporting Information [Line Items]
Operating revenues	12,554	12,919	12,354
Operating revenues \| CECONY
Segment Reporting Information [Line Items]
Operating revenues	10,328	10,786	10,430
Operating revenues \| CECONY \| Electric
Segment Reporting Information [Line Items]
Operating revenues	8,172	8,437	8,131
Operating revenues \| CECONY \| Gas
Segment Reporting Information [Line Items]
Operating revenues	1,527	1,721	1,616
Operating revenues \| CECONY \| Steam
Segment Reporting Information [Line Items]
Operating revenues	629	628	683
Operating revenues \| O&R
Segment Reporting Information [Line Items]
Operating revenues	845	892	833
Operating revenues \| O&R \| Electric
Segment Reporting Information [Line Items]
Operating revenues	663	680	628
Operating revenues \| O&R \| Gas
Segment Reporting Information [Line Items]
Operating revenues	182	212	205
Operating revenues \| Competitive energy businesses
Segment Reporting Information [Line Items]
Operating revenues	1,383	1,244	1,096
Operating revenues \| Other
Segment Reporting Information [Line Items]
Operating revenues	(2)	(3)	(5)
Inter- segment revenues \| CECONY
Segment Reporting Information [Line Items]
Operating revenues	(110)	(106)	(103)
Inter- segment revenues \| CECONY \| Electric
Segment Reporting Information [Line Items]
Operating revenues	18	16	16
Inter- segment revenues \| CECONY \| Gas
Segment Reporting Information [Line Items]
Operating revenues	6	6	5
Inter- segment revenues \| CECONY \| Steam
Segment Reporting Information [Line Items]
Operating revenues	86	84	82
Inter- segment revenues \| Competitive energy businesses
Segment Reporting Information [Line Items]
Operating revenues	(2)	(10)	5
Inter- segment revenues \| Other
Segment Reporting Information [Line Items]
Operating revenues	$ 2	10	(5)
New Accounting Pronouncement, Early Adoption, Effect
Segment Reporting Information [Line Items]
Total assets		$ (237)	$ (196)

Derivative Instruments and Hedging Activities - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Investment Holdings [Line Items]
Energy supply and hedging activities credit exposure total	$ 212
Makeup of net credit exposure with commodity exchange brokers	146
Makeup of net credit exposure independent system operators	50
Makeup of net credit exposure with investment-grade counterparties	8
Makeup of net credit exposure non-investment grade/non-rated counterparties	8
CECONY
Investment Holdings [Line Items]
Energy supply and hedging activities credit exposure total	$ 26

Derivative Instruments and Hedging Activities - Fair Values of Commodity Derivatives Including Offsetting of Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	$ (207)	$ (163)
Gross Amounts Offset	46	140
Net Amounts of Assets/ (Liabilities)	(161)	(23)
Margin deposits	26	27
Fair Value of Derivative Liabilities, Current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(144)	(242)
Gross Amounts Offset	78	139
Net Amounts of Assets/ (Liabilities)	(66)	(103)
Fair Value of Derivative Liabilities, Liabilities Held For Sale, Current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(115)	0
Gross Amounts Offset	50	0
Net Amounts of Assets/ (Liabilities)	(65)	0
Fair Value of Derivative Liabilities, Non-current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(102)	(66)
Gross Amounts Offset	63	91
Net Amounts of Assets/ (Liabilities)	(39)	25
Fair Value of Derivative Liabilities, Liabilities Held For Sale, Noncurrent
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(28)	0
Gross Amounts Offset	15	0
Net Amounts of Assets/ (Liabilities)	(13)	0
Fair Value of Derivative Liabilities
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(389)	(308)
Gross Amounts Offset	206	230
Net Amounts of Assets/ (Liabilities)	(183)	(78)
Fair Value of Derivative Assets, Current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	59	111
Gross Amounts Offset	(41)	(67)
Net Amounts of Assets/ (Liabilities)	18	44
Fair Value of Derivative Assets, Assets Held for Sale, Current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	51	0
Gross Amounts Offset	(50)	0
Net Amounts of Assets/ (Liabilities)	1	0
Fair Value of Derivative Assets, Non-current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	57	34
Gross Amounts Offset	(54)	(23)
Net Amounts of Assets/ (Liabilities)	3	11
Fair Value of Derivative Assets, Assets Held for Sale, Noncurrent
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	15	0
Gross Amounts Offset	(15)	0
Net Amounts of Assets/ (Liabilities)	0	0
Fair Value of Derivative Assets
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	182	145
Gross Amounts Offset	(160)	(90)
Net Amounts of Assets/ (Liabilities)	22	55
CECONY
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(125)	(90)
Gross Amounts Offset	48	45
Net Amounts of Assets/ (Liabilities)	(77)	(45)
Margin deposits	26	25
CECONY \| Fair Value of Derivative Liabilities, Current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(121)	(96)
Gross Amounts Offset	71	48
Net Amounts of Assets/ (Liabilities)	(50)	(48)
CECONY \| Fair Value of Derivative Liabilities, Non-current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(92)	(42)
Gross Amounts Offset	56	32
Net Amounts of Assets/ (Liabilities)	(36)	(10)
CECONY \| Fair Value of Derivative Liabilities
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	(213)	(138)
Gross Amounts Offset	127	80
Net Amounts of Assets/ (Liabilities)	(86)	(58)
CECONY \| Fair Value of Derivative Assets, Current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	40	26
Gross Amounts Offset	(32)	(15)
Net Amounts of Assets/ (Liabilities)	8	11
CECONY \| Fair Value of Derivative Assets, Non-current
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	48	22
Gross Amounts Offset	(47)	(20)
Net Amounts of Assets/ (Liabilities)	1	2
CECONY \| Fair Value of Derivative Assets
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets/ (Liabilities)	88	48
Gross Amounts Offset	(79)	(35)
Net Amounts of Assets/ (Liabilities)	$ 9	$ 13

Derivative Instruments and Hedging Activities - Realized and Unrealized Gains or Losses on Commodity Derivatives (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	$ 2	$ (9)
Total deferred gains/(losses)	(177)	(56)
Net deferred gains/(losses)	(175)	(65)
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(186)	(123)
Purchased power expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(109)	(37)
Unrealized gain/(loss) on derivatives	(1)	(132)
Gas purchased for resale
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(106)	(115)
Non-utility revenue
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	30	29
Non Utility Operating Revenue
Pre-tax gain/(loss) recognized in income
Unrealized gain/(loss) on derivatives	1	4
Other Operations and Maintenance Expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(1)	0
Unrealized gain/(loss) on derivatives	(1)
Deferred Derivative Gains,Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	1	(10)
Deferred Derivative Gains, Long-term
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	1	1
Deferred Derivative Losses, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(16)	(75)
Recoverable Energy Costs, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(136)	36
Deferred Derivative Losses, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(25)	(17)
CECONY
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	2	(6)
Total deferred gains/(losses)	(161)	(61)
Net deferred gains/(losses)	(159)	(67)
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(1)	0
CECONY \| Purchased power expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
CECONY \| Gas purchased for resale
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
CECONY \| Non-utility revenue
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
CECONY \| Other Operations and Maintenance Expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(1)	0
Unrealized gain/(loss) on derivatives	(1)
CECONY \| Deferred Derivative Gains,Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	2	(7)
CECONY \| Deferred Derivative Gains, Long-term
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	0	1
CECONY \| Deferred Derivative Losses, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(11)	(70)
CECONY \| Recoverable Energy Costs, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(127)	26
CECONY \| Deferred Derivative Losses, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	$ (23)	$ (17)

Derivative Instruments and Hedging Activities - Hedged Volume of Derivative Transactions (Detail)	12 Months Ended
	Dec. 31, 2015 DTH MWh MW gal
Electric Energy Derivative
Derivatives, Fair Value [Line Items]
Electric Energy (MWH) \| MWh	37,036,264
Electric Capacity Derivative
Derivatives, Fair Value [Line Items]
Capacity (MW) \| MW	21,174
Natural Gas Derivative
Derivatives, Fair Value [Line Items]
Natural Gas (Dt) \| DTH	50,052,794
Refined Fuels
Derivatives, Fair Value [Line Items]
Refined Fuels (gallons) \| gal	3,696,000
CECONY \| Electric Energy Derivative
Derivatives, Fair Value [Line Items]
Electric Energy (MWH) \| MWh	18,742,050
CECONY \| Electric Capacity Derivative
Derivatives, Fair Value [Line Items]
Capacity (MW) \| MW	12,000
CECONY \| Natural Gas Derivative
Derivatives, Fair Value [Line Items]
Natural Gas (Dt) \| DTH	47,540,000
CECONY \| Refined Fuels
Derivatives, Fair Value [Line Items]
Refined Fuels (gallons) \| gal	3,696,000
Discontinued Operations, Held-for-sale \| Electric Energy Derivative
Derivatives, Fair Value [Line Items]
Electric Energy (MWH) \| MWh	16,381,544
Discontinued Operations, Held-for-sale \| Electric Capacity Derivative
Derivatives, Fair Value [Line Items]
Capacity (MW) \| MW	7,262
Discontinued Operations, Held-for-sale \| Natural Gas Derivative
Derivatives, Fair Value [Line Items]
Natural Gas (Dt) \| DTH	580,362

Derivative Instruments and Hedging Activities - Aggregate Fair Value of Companies' Derivative Instruments with Credit-Risk-Related Contingent Features (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Derivatives, Fair Value [Line Items]
Aggregate fair value – net liabilities	$ 106
Collateral posted	18
Downgrade One Level from Current Ratings
Derivatives, Fair Value [Line Items]
Derivatives in net liability position additional collateral	9
Downgrade to Below Investment Grade from Current Ratings
Derivatives, Fair Value [Line Items]
Derivatives in net liability position additional collateral	142
Derivatives in net asset position additional collateral	6
Additional Collateral Required Due To Loss Of Unsecured Credit
Derivatives, Fair Value [Line Items]
Collateral posted	16
CECONY
Derivatives, Fair Value [Line Items]
Aggregate fair value – net liabilities	81
Collateral posted	17
CECONY \| Downgrade One Level from Current Ratings
Derivatives, Fair Value [Line Items]
Derivatives in net liability position additional collateral	6
CECONY \| Downgrade to Below Investment Grade from Current Ratings
Derivatives, Fair Value [Line Items]
Derivatives in net liability position additional collateral	$ 104

Fair Value Measurements - Additional Information (Detail) - Purchased power expense - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair value, assets measured on recurring basis, change in unrealized gain (loss)	$ (8)	$ 2
Competitive energy businesses
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gain (loss) on Level 3 energy derivative liabilities	$ (14)	$ 27

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	$ 345,000,000	$ 361,000,000
Total liabilities	183,000,000	78,000,000
Transfers between levels 1,2 and 3	0	0
CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	311,000,000	299,000,000
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	187,000,000	166,000,000
Total liabilities	17,000,000	18,000,000
Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	172,000,000	156,000,000
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	200,000,000	194,000,000
Total liabilities	286,000,000	246,000,000
Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	114,000,000	109,000,000
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	14,000,000	28,000,000
Total liabilities	8,000,000	8,000,000
Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	8,000,000	13,000,000
Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	47,000,000	82,000,000
Derivative liabilities	105,000,000	78,000,000
Commodity \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	35,000,000	38,000,000
Derivative liabilities	86,000,000	58,000,000
Commodity \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2,000,000	3,000,000
Derivative liabilities	16,000,000	18,000,000
Commodity \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1,000,000	1,000,000
Derivative liabilities	14,000,000	16,000,000
Commodity \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	25,000,000	78,000,000
Derivative liabilities	153,000,000	246,000,000
Commodity \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	9,000,000	3,000,000
Derivative liabilities	129,000,000	91,000,000
Commodity \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	13,000,000	28,000,000
Derivative liabilities	1,000,000	8,000,000
Commodity \| Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	8,000,000	13,000,000
Commodity Contract, Held For Sale
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1,000,000	0
Derivative liabilities	78,000,000
Commodity Contract, Held For Sale \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	1,000,000
Commodity Contract, Held For Sale \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	63,000,000	0
Derivative liabilities	133,000,000
Commodity Contract, Held For Sale \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1,000,000	0
Derivative liabilities	7,000,000
Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	297,000,000	279,000,000
Other \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	276,000,000	261,000,000
Other \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	185,000,000	163,000,000
Other \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	171,000,000	155,000,000
Other \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	112,000,000	116,000,000
Other \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	105,000,000	106,000,000
Netting Adjustments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	(56,000,000)	(27,000,000)
Total liabilities	(128,000,000)	(194,000,000)
Netting Adjustments \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	17,000,000	21,000,000
Netting Adjustments \| Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7,000,000	(27,000,000)
Derivative liabilities	(65,000,000)	(194,000,000)
Netting Adjustments \| Commodity \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	17,000,000	21,000,000
Derivative liabilities	(57,000,000)	(49,000,000)
Netting Adjustments \| Commodity Contract, Held For Sale
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(63,000,000)	$ 0
Derivative liabilities	$ (63,000,000)

Fair Value Measurements - Reconciliation of Beginning and Ending Net Balances for Assets and Liabilities Measured at Level 3 Fair Value (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 20	$ 9
Included in earnings	(20)	30
Included in regulatory assets and liabilities	1	7
Purchases	11	22
Settlements	(6)	(48)
Ending Balance	6	20
CECONY
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	13	6
Included in earnings	(6)	2
Included in regulatory assets and liabilities	0	7
Purchases	5	16
Settlements	(4)	(18)
Ending Balance	$ 8	$ 13

Variable Interest Entities - Additional Information (Detail)	1 Months Ended	12 Months Ended
	May. 31, 2014 MW	Dec. 31, 2015 USD ($) VIE MW	Dec. 31, 2014 USD ($) MW	Dec. 31, 2013 USD ($)
Variable Interest Entity [Line Items]
Investments		$ 884,000,000	$ 816,000,000
Proceeds from sale of solar electric production projects		0	108,000,000	$ 0
Gain on sale of solar electric production projects		0	45,000,000	$ 0
Noncontrolling interest		9,000,000	$ 9,000,000
Variable Interest Entity, Not Primary Beneficiary \| California Solar
Variable Interest Entity [Line Items]
Percentage of variable interests	50.00%
Generating Capacity (MW AC) \| MW	110
Variable Interest Entity, Primary Beneficiary \| Texas Solar 4
Variable Interest Entity [Line Items]
Percentage of variable interests			80.00%
Payments to acquire businesses			$ 49,000,000
VIE consolidated, carrying amount, assets and liabilities, net		$ 58,000,000	58,000,000
Variable Interest Entity, Not Primary Beneficiary, Aggregated Disclosure
Variable Interest Entity [Line Items]
Percentage of variable interests		50.00%
Variable Interest Entity, Not Primary Beneficiary, Aggregated Disclosure \| Panoche Valley
Variable Interest Entity [Line Items]
Percentage of variable interests		50.00%
Investments		$ 37,000,000
Notes receivable, related parties		$ 77,000,000
CECONY
Variable Interest Entity [Line Items]
Number of potential VIEs, long-term electricity purchase agreements \| VIE		2
Investments		$ 286,000,000	$ 271,000,000
California Solar
Variable Interest Entity [Line Items]
Percentage of membership interests sold	50.00%
Proceeds from sale of solar electric production projects		108,000,000
Gain on sale of solar electric production projects		45,000,000
Gain (loss) on investments, net of tax		$ 26,000,000
California \| Variable Interest Entity, Not Primary Beneficiary \| Panoche Valley
Variable Interest Entity [Line Items]
Generating Capacity (MW AC) \| MW		247
Texas \| Variable Interest Entity, Primary Beneficiary \| Texas Solar 4
Variable Interest Entity [Line Items]
Generating Capacity (MW AC) \| MW			40
Noncontrolling Interest
Variable Interest Entity [Line Items]
Noncontrolling interest		$ 9,000,000	$ 9,000,000

Variable Interest Entities - Summary of Sale and Deconsolidation of California Solar (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Proceeds from sale, net of transaction costs of $1	$ 0	$ 108	$ 0
California Solar
Schedule of Equity Method Investments [Line Items]
Transaction costs		$ 1
Proceeds from sale, net of transaction costs of $1	108
California Solar \| Disposal Group, Disposed of by Sale, Not Discontinued Operations
Schedule of Equity Method Investments [Line Items]
Non-utility property, less accumulated depreciation	(341)
Other assets, including working capital	(31)
Long-term debt, including current portion	217
Other liabilities	9
Gain on sale of solar electric production projects	(45)
Equity method investment upon deconsolidation	$ (83)

Variable Interest Entities - Net Assets of Texas Solar 4 (Details) - Texas Solar 4 - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Restricted cash	$ 9	$ 13
Receivable from parent company	32	0
Non-utility property, less accumulated depreciation of $5 and $1, respectively	107	108
Other assets	11	14
Total assets	159	135
Long-term debt due within one year	2	66
Other liabilities	37	11
Long-term debt	62	0
Total liabilities	101	77
Depreciation	$ 5	$ 1

Variable Interest Entities - Summary of VIEs (Detail)	1 Months Ended	12 Months Ended
Variable Interest Entities - Summary of VIEs (Detail)	May. 31, 2014	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014
Variable Interest Entity, Not Primary Beneficiary \| Copper Mountain Solar 3 \| Nevada
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		128
Power Purchase Agreement Term in Years		20 years
Year of Initial Investment		2014
Maximum Exposure to Loss (In Millions) \| $		$ 189,000,000
Variable Interest Entity, Not Primary Beneficiary \| Panoche Valley \| California
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		124
Power Purchase Agreement Term in Years		20 years
Year of Initial Investment		2015
Maximum Exposure to Loss (In Millions) \| $		$ 114,000,000
Variable Interest Entity, Not Primary Beneficiary \| Mesquite Solar 1 \| Arizona
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		83
Power Purchase Agreement Term in Years		20 years
Year of Initial Investment		2013
Maximum Exposure to Loss (In Millions) \| $		$ 110,000,000
Variable Interest Entity, Not Primary Beneficiary \| Copper Mountain Solar 2 \| Nevada
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		75
Power Purchase Agreement Term in Years		25 years
Year of Initial Investment		2013
Maximum Exposure to Loss (In Millions) \| $		$ 85,000,000
Variable Interest Entity, Not Primary Beneficiary \| California Solar
Variable Interest Entity [Line Items]
Percentage of variable interests	50.00%
Variable Interest Entity, Not Primary Beneficiary \| California Solar \| California
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		55
Power Purchase Agreement Term in Years		25 years
Year of Initial Investment		2012
Maximum Exposure to Loss (In Millions) \| $		$ 75,000,000
Variable Interest Entity, Not Primary Beneficiary \| Broken Bow II \| Nebraska
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		38
Power Purchase Agreement Term in Years		25 years
Year of Initial Investment		2014
Maximum Exposure to Loss (In Millions) \| $		$ 55,000,000
Variable Interest Entity, Not Primary Beneficiary \| Pilesgrove \| New Jersey
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		9
Year of Initial Investment		2010
Maximum Exposure to Loss (In Millions) \| $		$ 26,000,000
Variable Interest Entity, Primary Beneficiary \| Texas Solar 4
Variable Interest Entity [Line Items]
Percentage of variable interests			80.00%
Variable Interest Entity, Primary Beneficiary \| Texas Solar 4 \| Texas
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW		32
Power Purchase Agreement Term in Years		25 years
Year of Initial Investment		2014
Maximum Exposure to Loss (In Millions) \| $		$ 17,000,000
Variable Interest Entity, Not Primary Beneficiary, Aggregated Disclosure
Variable Interest Entity [Line Items]
Percentage of variable interests		50.00%
Variable Interest Entity, Not Primary Beneficiary, Aggregated Disclosure \| Panoche Valley
Variable Interest Entity [Line Items]
Percentage of variable interests		50.00%
Minimum \| Solar Renewable Energy Credit Hedge \| Pilesgrove
Variable Interest Entity [Line Items]
Renewable energy credit (years)		3 years
Maximum \| Solar Renewable Energy Credit Hedge \| Pilesgrove
Variable Interest Entity [Line Items]
Renewable energy credit (years)		5 years

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Accrued liability - asset retirement obligations	$ 242	$ 188
Increase in liabilities for asset retirement obligations due to changes in estimated cash flows	82
Asset retirement obligations, accretion expense	8
Asset retirement obligations, liabilities settled	36
Asset retirement obligations, reductions	23	16
CECONY
Regulatory Liabilities [Line Items]
Accrued liability - asset retirement obligations	234	185
Increase in liabilities for asset retirement obligations due to changes in estimated cash flows	77
Asset retirement obligations, accretion expense	8
Asset retirement obligations, liabilities settled	36
Asset retirement obligations, reductions	$ 23	$ 16

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jan. 31, 2016
Related Party Transaction [Line Items]
Ownership interest, percentage	45.70%
CECONY
Related Party Transaction [Line Items]
Sale of natural gas	$ 54,000,000	$ 80,000,000	$ 72,000,000
Funding limit of CECONY to O&R (not to exceed)	250,000,000
O&R
Related Party Transaction [Line Items]
Outstanding loans to O&R	$ 0	$ 0
Related Party, Lending of Funds \| CECONY
Related Party Transaction [Line Items]
Lending period (not more than) (months)	12 months
Subsequent Event
Related Party Transaction [Line Items]
Ownership interest, percentage				45.70%

Assets Held for Sale (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
Assets Held for Sale (Details) - USD ($) $ in Millions	Dec. 31, 2015	Oct. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and temporary cash investments	$ 4		$ 4	$ 0	$ 0
Total current assets	157		157	0
Total current liabilities	89		89	$ 0
Discontinued Operations, Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and temporary cash investments	4		4
Accounts receivable, less allowance for uncollectible accounts of $8	64		64
Accrued unbilled revenue	65		65
Other assets	3		3
Total current assets	136		136
Utility plant, less accumulated depreciation of $6	14		14
Non-utility property, less accumulated depreciation of $13	4		4
Regulatory assets	3		3
Total assets held for sale	157		157
Fair value of derivative liabilities	65		65
Accounts payable	5		5
Other	3		3
Total current liabilities	73		73
Fair value of derivative liabilities	13		13
Long-term debt	3		3
Total liabilities held for sale	89		89
Allowance for uncollectible accounts	8
Depreciation, utility plant	6
Depreciation, non-utility property	13
Retail Electric Supply Business \| Discontinued Operations, Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and temporary cash investments	0		0
Accounts receivable, less allowance for uncollectible accounts of $8	64		64
Accrued unbilled revenue	64		64
Other assets	2		2
Total current assets	130		130
Utility plant, less accumulated depreciation of $6	0		0
Non-utility property, less accumulated depreciation of $13	4		4
Regulatory assets	0		0
Total assets held for sale	134		134
Fair value of derivative liabilities	65		65
Accounts payable	5		5
Other	1		1
Total current liabilities	71		71
Fair value of derivative liabilities	13		13
Long-term debt	0		0
Total liabilities held for sale	84		84
Pike \| Discontinued Operations, Held-for-sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses		$ 16
Impairment charge on assets held for sale	5		5
Impairment of long-lived assets to be disposed of, net of tax	3
Cash and temporary cash investments	4		4
Accounts receivable, less allowance for uncollectible accounts of $8	0		0
Accrued unbilled revenue	1		1
Other assets	1		1
Total current assets	6		6
Utility plant, less accumulated depreciation of $6	14		14
Non-utility property, less accumulated depreciation of $13	0		0
Regulatory assets	3		3
Total assets held for sale	23		23
Fair value of derivative liabilities	0		0
Accounts payable	0		0
Other	2		2
Total current liabilities	2		2
Fair value of derivative liabilities	0		0
Long-term debt	3		3
Total liabilities held for sale	$ 5		$ 5

Schedule I - Condensed Financial Information - Condensed Statement of Income and Comprehensive Income (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Condensed Consolidating Statement Of Operation [Line Items]
Interest expense	$ (653)	$ (591)	$ (719)
NET INCOME	1,193	1,092	1,062
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 1,204	$ 1,072	$ 1,090
Net Income Per Share – Basic (dollars per share)	$ 4.07	$ 3.73	$ 3.62
Net Income Per Share – Diluted (dollars per share)	4.05	3.71	3.61
DIVIDENDS DECLARED PER COMMON SHARE (dollars per share)	$ 2.60	$ 2.52	$ 2.46
Average Number Of Shares Outstanding—Basic (In Millions) (shares)	293.0	292.9	292.9
Average Number Of Shares Outstanding—Diluted (In Millions) (shares)	294.4	294.0	294.4
Consolidated Edison Inc
Schedule Of Condensed Consolidating Statement Of Operation [Line Items]
Equity in earnings of subsidiaries	$ 1,195	$ 1,101	$ 1,062
Other income (deductions), net of taxes	27	19	29
Interest expense	(29)	(28)	(29)
NET INCOME	1,193	1,092	1,062
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 1,204
Comprehensive Income		$ 1,072	$ 1,090
Net Income Per Share – Basic (dollars per share)	$ 4.07	$ 3.73	$ 3.62
Net Income Per Share – Diluted (dollars per share)	4.05	3.71	3.61
DIVIDENDS DECLARED PER COMMON SHARE (dollars per share)	$ 2.6	$ 2.52	$ 2.46
Average Number Of Shares Outstanding—Basic (In Millions) (shares)	293.0	292.9	292.9
Average Number Of Shares Outstanding—Diluted (In Millions) (shares)	294.4	294.0	294.4

Schedule I - Condensed Financial Information - Condensed Statement of Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	$ 1,193	$ 1,092	$ 1,062
Common stock dividends	733	739	721
Change in Assets:
Special deposits	5	312	(257)
Income taxes receivable	58	(224)	0
Other – net	(32)	4	34
Net Cash Flows from Operating Activities	3,277	2,831	2,552
INVESTING ACTIVITIES
Net Cash Flows Used in Investing Activities	(3,657)	(2,759)	(2,659)
FINANCING ACTIVITIES
Net proceeds of short-term debt	729	(651)	912
Retirement of long-term debt	(500)	(480)	(709)
Issuance of common shares for stock plans, net of repurchases	1	(10)	(8)
Common stock dividends	733	739	721
NET CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES	629	(47)	387
NET CHANGE FOR THE PERIOD	249	25	280
BALANCE AT BEGINNING OF PERIOD	699	674
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	944	699	674
Consolidated Edison Inc
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	1,193	1,092	1,062
Equity in earnings of subsidiaries	(1,195)	(1,101)	(1,062)
Common stock dividends	733	739	721
Change in Assets:
Special deposits	0	314	(264)
Income taxes receivable	58	(224)	0
Other – net	(382)	(199)	166
Net Cash Flows from Operating Activities	635	642	680
INVESTING ACTIVITIES
Contributions to subsidiaries	(15)	(1)	0
Net Cash Flows Used in Investing Activities	(15)	(1)	0
FINANCING ACTIVITIES
Net proceeds of short-term debt	162	101	58
Retirement of long-term debt	(2)	(2)	(1)
Issuance of common shares for stock plans, net of repurchases	1	(10)	(8)
Common stock dividends	733	739	721
NET CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES	(572)	(650)	(672)
NET CHANGE FOR THE PERIOD	48	(9)	8
BALANCE AT BEGINNING OF PERIOD	3	12	4
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	51	3	12
CECONY
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	1,084	1,058	1,020
Change in Assets:
Other – net	38	48	(30)
Net Cash Flows from Operating Activities	2,819	2,430	2,643
INVESTING ACTIVITIES
Net Cash Flows Used in Investing Activities	(2,638)	(2,304)	(2,417)
FINANCING ACTIVITIES
Net proceeds of short-term debt	583	(760)	789
Retirement of long-term debt	(350)	(475)	(700)
NET CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES	17	(114)	54
NET CHANGE FOR THE PERIOD	198	12	280
BALANCE AT BEGINNING OF PERIOD	645	633	353
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	843	645	633
CECONY \| Consolidated Edison Inc
Condensed Cash Flow Statements, Captions [Line Items]
Common stock dividends	872	712	728
FINANCING ACTIVITIES
Common stock dividends	872	712	728
O&R \| Consolidated Edison Inc
Condensed Cash Flow Statements, Captions [Line Items]
Common stock dividends	81	40	38
FINANCING ACTIVITIES
Common stock dividends	81	40	38
Competitive energy businesses \| Consolidated Edison Inc
Condensed Cash Flow Statements, Captions [Line Items]
Common stock dividends	8	8	12
FINANCING ACTIVITIES
Common stock dividends	$ 8	$ 8	$ 12

Schedule I - Condensed Financial Information - Condensed Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and temporary cash investments	$ 944	$ 699	$ 674
Special deposits	3	8
Accounts receivable – other	1,052	1,201
Income taxes receivable	166	224
Prepayments	177	163
Other current assets	191	278
TOTAL CURRENT ASSETS	3,836	3,716
Investments in subsidiaries	884	816
Goodwill	429	429
Other noncurrent assets (b)	8,713	9,712
TOTAL ASSETS	45,642	44,071	40,451
CURRENT LIABILITIES
Long-term debt due within one year	739	560
Notes payable	1,529	800
Accrued taxes	62	72
Other current liabilities	525	492
TOTAL CURRENT LIABILITIES	4,720	3,757
LONG-TERM DEBT	12,006	11,546
Shareholders’ Equity
Equity	13,052	12,576
TOTAL LIABILITIES AND EQUITY	45,642	44,071
Deferred finance costs	91	85
Consolidated Edison Inc
CURRENT ASSETS
Cash and temporary cash investments	51	3	12	$ 4
Special deposits	1	1
Accounts receivable – other	4	0
Income taxes receivable	166	224
Accounts receivable from affiliated companies	517	381
Prepayments	34	5
Other current assets	17	4
TOTAL CURRENT ASSETS	790	618
Investments in subsidiaries	12,737	12,277
Goodwill	406	406
Deferred income tax	11	18
Other noncurrent assets (b)	7	8
TOTAL ASSETS	13,951	13,327
CURRENT LIABILITIES
Long-term debt due within one year	2	2
Notes payable	437	274
Accounts payable to affiliated companies	146	147
Accrued taxes	0	13
Other current liabilities	10	10
TOTAL CURRENT LIABILITIES	595	446
Total Liabilities	595	446
LONG-TERM DEBT	304	305
Shareholders’ Equity
Common stock, including additional paid-in capital	5,062	5,023
Retained earnings	7,990	7,553
Equity	13,052	12,576
TOTAL LIABILITIES AND EQUITY	13,951	13,327
New Accounting Pronouncement, Early Adoption, Effect
CURRENT ASSETS
TOTAL ASSETS		(237)	$ (196)
New Accounting Pronouncement, Early Adoption, Effect \| Other Assets
Shareholders’ Equity
Deferred finance costs	(91)	(85)
New Accounting Pronouncement, Early Adoption, Effect \| Other Assets \| Consolidated Edison Inc
Shareholders’ Equity
Deferred finance costs		(3)
New Accounting Pronouncement, Early Adoption, Effect \| Long-term Debt
Shareholders’ Equity
Deferred finance costs	$ 91	85
New Accounting Pronouncement, Early Adoption, Effect \| Long-term Debt \| Consolidated Edison Inc
Shareholders’ Equity
Deferred finance costs		$ 3

Schedule II - Valuation and Qualifying Accounts - Valuation and Qualifying Accounts (Detail) - Allowance For Uncollectible Accounts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 106	$ 103	$ 105
Charged To Costs And Expenses	77	98	86
Charged To Other Accounts	0	0	0
Deductions	87	95	88
Balance At End of Period	96	106	103
CECONY
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	98	95	96
Charged To Costs And Expenses	69	91	82
Charged To Other Accounts	0	0	0
Deductions	76	88	83
Balance At End of Period	$ 91	$ 98	$ 95

General (Details)	12 Months Ended
General (Details)	Dec. 31, 2015 subsidiary registrant
Accounting Policies [Abstract]
Number of registrants \| registrant	2
Number of subsidiaries \| subsidiary	2

Summary of Significant Accounting Policies - Schedule of Total Excise Taxes Recorded in Operating Revenues (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Excise Taxes [Line Items]
Excise taxes	$ 354	$ 365	$ 354
CECONY
Schedule of Excise Taxes [Line Items]
Excise taxes	$ 331	$ 343	$ 329

Leases - Schedule of Capital Leases (Detail) - Common - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property Subject to or Available for Operating Lease [Line Items]
Utility Plant	$ 3	$ 3
CECONY
Property Subject to or Available for Operating Lease [Line Items]
Utility Plant	$ 2	$ 1

Fair Value Measurements - Schedule of Commodity Derivatives (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) $ / MWh $ / kW-month
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Valuation Techniques	Discounted Cash Flow
Electricity
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Valuation Techniques	Discounted Cash Flow
Natural Gas
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Valuation Techniques	Discounted Cash Flow
Transmission Congestion Contracts/Financial Transmission Rights
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Valuation Techniques	Discounted Cash Flow
Minimum \| Transmission Congestion Contracts/Financial Transmission Rights \| Discount to Adjust Auction Prices for Inter-Zonal Forward Price Curves
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	40.80%
Minimum \| Transmission Congestion Contracts/Financial Transmission Rights \| Discount to Adjust Auction Prices for Historical Monthly Realized Settlements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	37.50%
Minimum \| Transmission Congestion Contracts/Financial Transmission Rights \| Inter-Zonal Forward Price Curves Adjusted for Historical Zonal Losses
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per kW-month)	(6.35)
Maximum \| Transmission Congestion Contracts/Financial Transmission Rights \| Discount to Adjust Auction Prices for Inter-Zonal Forward Price Curves
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	62.10%
Maximum \| Transmission Congestion Contracts/Financial Transmission Rights \| Discount to Adjust Auction Prices for Historical Monthly Realized Settlements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	82.20%
Maximum \| Transmission Congestion Contracts/Financial Transmission Rights \| Inter-Zonal Forward Price Curves Adjusted for Historical Zonal Losses
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per kW-month)	5.59
Level 3
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives \| $	$ 6
Level 3 \| Electricity
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives \| $	(5)
Level 3 \| Natural Gas
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives \| $	1
Level 3 \| Transmission Congestion Contracts/Financial Transmission Rights
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives \| $	$ 10
CECONY \| Transmission Congestion Contracts
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Valuation Techniques	Discounted Cash Flow
CECONY \| Minimum \| Transmission Congestion Contracts \| Discount to Adjust Auction Prices for Inter-Zonal Forward Price Curves
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	40.80%
CECONY \| Minimum \| Transmission Congestion Contracts \| Discount to Adjust Auction Prices for Historical Monthly Realized Settlements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	37.50%
CECONY \| Maximum \| Transmission Congestion Contracts \| Discount to Adjust Auction Prices for Inter-Zonal Forward Price Curves
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	62.10%
CECONY \| Maximum \| Transmission Congestion Contracts \| Discount to Adjust Auction Prices for Historical Monthly Realized Settlements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range in percentage	82.20%
CECONY \| Level 3 \| Transmission Congestion Contracts
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives \| $	$ 8
Forward Prices \| Minimum \| Electricity
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per MWh/Dt)	18.33
Forward Prices \| Minimum \| Natural Gas
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per MWh/Dt)	(7.60)
Forward Prices \| Maximum \| Electricity
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per MWh/Dt)	77.50
Forward Prices \| Maximum \| Natural Gas
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per MWh/Dt)	5.55
Forward Capacity Prices \| Minimum \| Electricity
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per MWh/Dt) \| $ / kW-month	1.17
Forward Capacity Prices \| Maximum \| Electricity
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per MWh/Dt) \| $ / kW-month	7.50